Gas Pipeline Pricing: Evolution, Alternatives and Risks
Gas Pipeline Pricing Evolution – MeetingThe Challenges of Modern Markets
Gas pipeline prices (rates or tolls) in the United States have evolved over the time since passage of the Natural Gas Act (NGA) in 1938[i] from a strict cost-plus-profit model to a more indirectly regulated regime today. This article discusses past and present pricing alternatives and the ramifications of a number of current risks facing pipeline developers and their customers.
The first (and still used) cost-plus pricing models determined prices by employing “cost of service” principles. The resulting prices are either known as “Stated Rates” or “Cost of Service Rates.” Stated Rates remain fixed in a pipeline’s base tariff between rate change dates, such as the dates that general rate changes are implemented. Cost of Service rates vary periodically between the system-wide rate change dates as the inputs into the cost of service formula change.
Stated Rates please regulators because the pipeline owner experiences incentives to reduce costs as a way to improve profits, thereby also encouraging rate stability. The cost reductions may be passed on to shippers if rates are reduced. The gas pipeline industry today faces claims by gas producer interests, some shippers and some state regulators that the efficiency incentives under Stated Rates have been too strong. Some of those parties argue that the NGA should be changed in a way that successful rate challenges would occasion relief back to the date of a rate complaint, rather than being effective only prospectively as under current law.
Costs of Service rates usually fall flat with regulators today because they tend to guarantee profit results and do not provide substantial efficiency incentives. However, Cost of Service formula rates still exist under specific contract rates with shippers because of the shippers’ desire to not pay more than actual costs. Cost of Service rates, depending on how they are defined, may create extra administrative and audit burdens. However, in some situations Cost of Service rates can be useful as a means of resolving disputes between a pipeline and its customers.
Cost-Plus Pricing Fundamentals
For companies that calculate rates under cost-plus pricing, one of the most important and contentious cost elements is the cost of common equity. Cost of service, or the revenue requirement of the utility, includes operating expenses, taxes, return on rate base including the cost of debt and equity financing, depreciation, and a reduction for incidental revenues.
To calculate the return on rate base, it is necessary to first calculate rate base. This item represents the net current investment in utility facilities that has been financed by investors. Rate base includes the cost of property, reduced by accumulated depreciation and deferred income taxes. Rate base also includes operating capital, such as materials and supplies inventories and prepayments.
The weighted average cost of debt and equity, or return on rate base, includes: (1) the sum of the cost of debt multiplied by the percentage of the total capital structure that is financed by debt, and (2) the cost of each source of equity financing multiplied by the percentage of the total capital structure that is financed by each equity source. Once the weighted cost of each financing source is calculated, the costs of all the financing sources are summed to derive the total weighted average cost of capital. The cost of common equity is generally the subject of much dispute and litigation, the details of which are beyond the scope of this article except to say that some new pricing methods may in part have the advantage of bypassing such disputes.
The Importance of Perceived Gas Pipeline Market Power
The U. S. federal regulatory regime rests on the regulatory importance of perceived (or actual) gas pipeline market power[ii]. At the industry’s inception the concept of cost-plus pricing reflected the idea that gas pipelines are essential utilities to the public, costly to duplicate, and have the potential to exercise market power; i. e., gas pipelines if left unrestrained by regulation could presumably exercise market power by charging rates above the cost of service rate and/or competitive rate.
The Evolution of Market-Oriented Pricing Strategies
Market-oriented strategies may be employed to develop successful gas pipeline projects under regulatory policy changes that occurred in 1996 and 1999.[iii] During those years, the FERC issued policy statements that enhanced the competitive landscape for new natural gas pipelines and for expansions of existing pipelines.
1996 Developments –
At the urging of the pipeline industry, in early 1996 the FERC issued its Statement of Policy on Alternatives to Traditional Cost-of-Service Ratemaking and its companion Policy on Regulation of Negotiated Services of Natural Gas Pipelines (1996 Policy Statement)[iv]. These documents became important as permitting indirectly market responsive pricing for pipeline transportation through a price-capped rate regime.
The 1996 Policy Statement introduced two new concepts for both the pricing of new gas pipeline infrastructure and for fostering markets for ongoing gas storage and transportation transactions. Under the first concept, “negotiated rates,” the pipeline and its customers by agreement may deviate from normal cost-plus tariff pricing. As an example, variations from the usually required straight-fixed variable pricing method (“SFV”)[v] are permitted. In addition, the pipeline may propose innovative cost of service calculation methods, such as rate levelization plans.[vi]
Negotiated rates are attractive to shippers because they allow better matching of cost calculations by service period to ability to pay, and such plans can result in a fixed rate for a number of years that is not subject to rate case disputes. For example, a rate levelization regime may benefit shippers by providing significantly lower initial prices than the traditional cost of service and declining rate base methodology (Traditional Rate Method).[vii] (Indeed, some projects very likely won’t get built today at all unless a levelized price is used, particularly because the FERC no longer permits existing shippers to subsidize expansions, as further discussed below.)
The second important idea in the 1996 Policy Statement is the concept of a “recourse rate.” As a predicate to permitting flexible, negotiated rates, the FERC required a calculation of a ceiling price to serve as a constraint on potential monopoly pricing power. Recourse rates for pipeline infrastructure additions have devolved generally into a price that is established under the Traditional Rate Method.[viii] The FERC required that such recourse rates would always be offered as an alternative to negotiated prices. The Commission ruled that costs and revenues related to negotiated services must be separately identified in pipeline records to facilitate the review of the effects of such services during general rate case proceedings.
When a rate case arises, the pipeline must be prepared to assume the full risk of its negotiated services without seeking discount adjustments in establishing the billing determinant levels used to calculate prices. Cost allocations among the pipeline’s various services must be calculated as though the negotiated service shippers are paying maximum recourse rates. As a result of these rules, entering into negotiated transactions exposes the pipeline to the full risk of each transaction, but with pricing tools needed to meet a broader market demand and the potential for improved earnings due to lighter regulation over price.
1999 Developments –
Pricing principles continued to evolve with the issuance of an order that departed dramatically from past pricing principles. Prior to 1999, a debate raged in the industry regarding which expansion project costs would be rolled-in, or averaged into, existing rates and which projects involve costs so significant that they should be priced on a stand-alone basis, which is referred to as incremental pricing.[ix]
Under the new pricing policy[x], the Commission stated:
“The threshold requirement in establishing the public convenience and necessity for existing pipelines proposing an expansion project is that the pipeline must be prepared to financially support the project without relying on subsidization from its existing customers.”
The Commission explained that the requirement for projects to be able to stand on their own without subsidies “…recognizes that a policy of incrementally pricing facilities sends the proper price signals to the market …the market will then decide whether a project is financially viable.” The FERC set in stone the principle that existing customers should not have to subsidize a project that does not serve them. This no-subsidy principle therefore made it more difficult to build new projects in competition with other more depreciated pipeline systems without the tools available from the newer, more creative pricing methods. However, rolled-in pricing was still permitted in certain circumstances, such as when a project would reduce existing rates or if the project is constructed solely to enhance system flexibility or reliability.
Economic and Regulatory Approaches in a New Environment
The Environment Today –
Significant economic, environmental and political pressures surround new infrastructure projects. These issues confront all stakeholders: governmental agencies, project sponsors, debt holders and gas consumers. With the disappearance of formal public convenience and necessity hearings in most regulatory jurisdictions, regulators increasingly rely on the confluence of market forces to decide which projects should be built. Today market forces are used to: (1) select among potential project sponsors, (2) allocate capacity among shippers and (3) create contractual means to mitigate project risks (such as the risk of a cost overrun or the risk of shipper default). Whether project sponsors build a project generally no longer is dependent on regulatory approval, rather sponsors are at risk for their investment decisions.
Since the market decides those matters, then logically market forces in many instances should also be permitted to select the means of pricing the projects, both over the short-term and long-term. However, to this point public policy has not been resolved in favor of unbridled market-based pricing of all gas transmission projects due to a strong lingering concern that gas pipelines are uniquely invested in the public welfare, are costly to duplicate and good alternatives to pipeline transportation do not exist in all geographic and product markets. Nevertheless, the FERC’s current incremental pricing and negotiated rates policies permit more market-responsive prices than were possible in prior years.
Blending Regulatory and Negotiated Rate Options –
Negotiated rates can be viewed as economically efficient because they bring a willing buyer and willing seller together in an environment where potential market power is constrained. In practice, negotiated prices are not a “one size fits all” proposition. A key dynamic of such prices is how the parties choose to deal with the length of the pricing arrangement, considering particularly that (for projects to secure debt financing) a degree of certainty usually must be achieved over contract terms of 10 or 15 years, or more. One issue that hasn’t, in my opinion, been dealt with completely yet by regulators or project participants is what will happen to the rates, depreciation recovery and ultimate project success once existing negotiated rate projects ramp off of their existing contracts. Today’s typical negotiated contracts with their 10 or 15 year contract terms are significantly shorter than the probable life of the facilities and related gas supplies. Project sponsors can’t be assured that they will be able to negotiate acceptable prices again with a new group of shippers. If such newly negotiated arrangements fail, then a host of regulatory issues could arise since it is not at all clear what rate base will then be available to the project sponsor under then existing regulatory principles.
We might ask, given the negotiated rate option’s availability, is there still a role for cost-plus pricing? Yes, there is for several reasons. First, the pipeline must establish initial rates for at least its interruptible services and re-justify or change those rates within three years of the inception of services under traditional rate principles. Second, a pipeline may have a mix of traditional services and other negotiated services. Third, the recourse price must be calculated under traditional pricing to establish a cost ceiling for comparison to negotiated prices, since the pipeline may not charge base tariff rates above the cost ceiling.
A number of variations in the methods that blend the best features of regulation and negotiation are possible and available to meet the concerns of all stakeholders over the entire life of the project. Such blending is probably under-used today and would often be desirable. For example, customers may have concerns about certain elements of the cost of service, such as concerns regarding potential unjust earnings that could occur with economic changes over a long time period, resulting in stale cost inputs such as an outdated return on equity. On the other hand, a project sponsor may need to be protected against a change to the basic project pricing formula that may harm the recovery of the expected returns over the life of the facilities, such as could occur with an interim switch from the levelized method to the traditional rate method[xi], or due to an unexpected, hypothetical regulatory rate base that may evolve if the project sponsor is forced to revert to traditional regulatory pricing. If more use were made of blended regulatory and negotiated pricing arrangements, conceivably very long-term arrangements could be set that would both assure all parties of reasonable outcomes and avoid unnecessary regulatory disputes.
Other Considerations in Managing Project Risks –
Project sponsors and project participants would be well advised to consider in their long-term strategic and financial plans strategies and changes that will be necessary after the initial contracts to adapt to changing market, supply and regulatory conditions. For example, an under-appreciated need relates to setting a long-run strategy to depreciate and recover project costs. Long-term depreciation policies can dramatically affect a variety of important financial results, such as financial statement profitability, the amount of property taxes that may be paid by the project, the timing of cash flows, and in sum project returns.
NOTES
[i] As explained by the Energy Information Administration on its web site, “… the Natural Gas Act (NGA) of 1938 was the first instance of direct Federal regulation of the natural gas industry. Concern about the exercise of market power by interstate pipeline companies prompted the passage of the NGA. That law gave the Federal Power Commission (FPC) (subsequently the Federal Energy Regulatory Commission (FERC)) the authority to set “just and reasonable rates” for the transmission or sale of natural gas in interstate commerce.”
[ii] The potential market power of owners of gas pipeline and storage projects has historically been restrained through cost-based pricing requirements implemented through the regulations pertinent to rate cases and other NGA Section 4 rate filings. Other constraints have occurred at the certification stage, such as through regulation of initial rates, implementing procedures for processing complaints, evaluating the impacts of projects on competitors and other stakeholders and through optional certificate rules. In recent years the methods used by FERC to review potential market power and to prevent its perceived ill effects have been refined through new policy statements, orders and regulations, such as Orders 436 and 500, et. al. Additional legislation, such as the Natural Gas Policy Act of 1978 and the Energy Policy Act of 2005, resulted in further extensions and elaboration of such energy policies.
[iii] Direct development of market-based rates for certain projects in competitive markets, such as for storage projects or in specific competitive gas transmission markets, is beyond the scope of this discussion. This article also does not discuss regulatory techniques used in other industries, such as price indexing employed for oil pipelines, because such approaches have not yet been applied by FERC to gas pipelines.
[iv] See 74 FERC ¶ 61,076 (1996).
[v] SFV prices mean charging fixed daily or monthly prices that include all pipeline costs, except costs that vary with throughput. Variable costs under this method are billed as gas volumes move through the pipeline system.
[vi] Rate levelization plans are intended to produce rates that remain stable throughout the terms of shipper contracts through some form of cost averaging. For example, a level rate may be calculated by changing the
timing of recovery of returns on investment or by modifying the timing of recovery of depreciation. Rate levelization plans are generally developed with the intent that the net present value of each particular project is the same as under the Traditional Rate Method, discussed below. The FERC has not defined a required levelization program in those instances where level rates are developed. Rate levelization plans that include straight-line depreciation may produce poor earnings in some years as a function of the way levelized prices are computed.
[vii] Under the Traditional Rate Method, prices, or rates, are calculated based on a declining rate base over the pipeline’s life and assuming the straight-line depreciation method. Assuming the absence of significant ongoing capital expenditures, rates under this method will tend to be the highest at the inception of service and will decline steadily thereafter.
[viii] To ensure that the recourse rate is not unduly restrictive, pipelines in certificate proceedings typically seek to calculate recourse rates under return and depreciation assumptions that make the negotiated price more attractive than the recourse rate.
[ix] Under the former pricing policy, the Commission applied a presumption in favor of rolled-in rates (rolling-in the expansion costs with pre-existing facilities’ costs) when the cost impact of the new facilities would result in a rate impact on existing customers of not more than five percent, and some system benefits would occur. In those instances, existing customers generally would bear these rate increases without being allowed to adjust their contract volumes.
[x] Certification of New Interstate Natural Gas Pipeline Facilities (Policy Statement) at 88 FERC ¶ 61,277.
[xi] Such a switch has been advocated by FERC Staff in a number of gas pipeline rate proceedings, creating very difficult issues for some of the parties.
