Barriers to Transmission Superhighways

Deck: 

History teaches us that the most successful American businesses emerge from the crucible of competition.

Fortnightly Magazine - May 2006

Important challenges still confront the development of a coherent strategy to create an efficient modern transmission system. Assuming the Federal Energy Regulatory Commission (FERC) and Congress are earnest about creating a 21st century grid—the Energy Policy Act of 2005 and FERC’s frantic schedule of activity indicate they are—new transmission ideas, projects, and technologies need to emerge.

Transmission innovation, often thought to be an oxymoron, will flourish more fully in an environment where there is a competitive struggle. History teaches us that the most successful American businesses emerge from the crucible of competition, especially when there are well-designed “rules of the road.”

For new transmission ideas and opportunities to come forward, the planning processes of transmission utilities, independent system operators (ISOs), and regional transmission organizations (RTOs) must not be allowed to become instruments that bar entry—intentionally or unintentionally—to new transmission projects. However, as transmission owners and operators continue to develop new and improved ways to manage their operations, two areas emerge as barriers to the entry of new transmission projects:

1. Ongoing efforts to develop a coherent large generation and transmission interconnection process. In PJM, often at the vanguard in the resolution of issues that emerge later in other competitive markets, the interconnection process continues to interfere with the problem of retiring generators. That process, in turn, is being held up by the slow development of a coherent capacity (or as PJM puts it, “reliability pricing”) policy.

2. The application of network versus point-to-point transmission services. The original cost and payback of the transmission system are embedded in “network service” tariffs. In some RTOs, the cost of new transmission needed to maintain reliability is covered by proposed transmission enhancement charges. But it is not clear where new transmission entities fit into these allocations.

Both the interconnection and the transmission pricing issues are wrapped around the axle of the most important unfinished piece of competitive market design: capacity (or, as PJM would have it, reliability) pricing.

Enduring Uncertainty

In the absence of reasonable capacity revenues, the owners of unprofitable generators take steps to close them down either by retirement or by mothballing. When the initial competitive markets were designed, little thought was given to this part of the business cycle. In the late 1990s, when investment in generation was booming, it was important to develop coherent rules governing the entry of generators. Similarly, transmission investment was all about how to manage the insertion of new generators into the grid, not about how to manage the withdrawal of generators out of the grid.

At the same time, it became very clear that regulators were unwilling or unable to abide extremely high energy prices, even when these were necessary for marginal units to recover some of their fixed costs. It also became very clear (to most observers) that the capacity market constructs of PJM, ISO New England (ISO-NE), and New York ISO (NY-ISO) structurally were flawed. Because load-serving entities (LSEs) placed zero value on any capacity in excess of their reliability obligations, capacity market prices were essentially zero in the markets where the generation boom of the late 1990s and early 2000s created surplus capacity. The combination of regulators’ unwillingness to let energy prices clear at a price that allowed marginal generators to recover fixed costs and the collapse of capacity market prices was devastating to the financial well being of generators.

Consequently, in the face of these two realities, many who built generating plants on a merchant basis went bankrupt. Others, such as utilities who had a more balanced portfolio of assets, announced they would retire plants. Such announcements, essentially distress signals, can be withdrawn if the distress comes to an end through band-aid measures such as reliability-must-run contracts or other side payments; or it can be more systematically addressed by implementing a payment program for capacity/reliability services along the lines of New York’s capacity demand curve, New England’s locational installed capacity policy (LICAP), or PJM’s reliability pricing model (RPM).

LICAP and RPM are not yet implemented fully in ISO-NE and PJM, and thus prolonged generator distress has led to a large number of announced generator retirements. As a re-sult, the ISO/RTO must plan as if the plants will be retired, and hence must make plans to install the transmission needed to maintain reliability in light of those retirements. If sub-sequent events, however, motivate the generators not to retire, then transmission may be overbuilt.

This results in an unintentional chicken-and-egg situation. Generators exercise their right to announce a retirement, thus causing the ISO both to raise the interconnection costs of proposed new projects and to call for more transmission. Subsequently, when and if capacity pricing reform better compensates for the full value of the plant in the grid, the generators then may announce they will un-retire a plant. That, in turn, allows the required interconnection costs of the new facilities to decline, and requires less transmission expansion in the regional transmission plan.

This fandango between an ISO/RTO and its generators has unintended consequences for new economic transmission development. Take, for example, a new and independent transmission line proposing to withdraw capacity and energy from one area and inject it into another. Suppose that half a dozen generators in the source market announce they will retire because the market’s capacity payments are inadequate. In these circumstances, the RTO would have to impose much larger interconnection costs on the transmission line to reflect this loss of capacity in its source market.

Suppose then, a year later, a more effective capacity payment mechanism is imposed, and the generators decide not to retire. The transmission project, nevertheless, has invested millions in network upgrades it ultimately did not need.

To take a recent example, American Electric Power (AEP) proposes that a new entity—AEP Transmission Co.—develop a 765-kV interstate transmission project. AEP’s new transco will be an LLC, not an LSE or a traditional transmission owner. It proposes to withdraw energy and capacity in the market surrounding AEP’s Amos substation in West Virginia and to inject energy and capacity in the market surrounding the Deans substation in Eastern New Jersey. If this proposal follows the usual interconnection process, it will be subject to interconnection costs (discussed above) in both the point of withdrawal and the point of injection.1

Under the PJM transmission development rules hashed out in the last four years, this project will need to request firm transmission injection rights (FTIRs) in New Jersey, if it plans to allow generators in West Virginia to offer capacity services to LSEs in New Jersey. If all of the generation in the retirement queue in New Jersey does in fact retire, there will be more injection capacity for the interstate project, and its interconnection costs will be lower; if that generation does not retire, there will be less injection capacity for the interstate project, and its interconnection costs will be higher.

The difference between the interconnection cost estimates can be in the tens of millions of dollars (and could delay implementation of a project). And yet, under the current market rules, because the capacity payment situation is so uncertain, the generators cannot be sure how long they will remain in service, and the interstate project sponsors cannot be sure what their interconnection costs will be.

This is a structural problem, one which helps explain why there are not more independent transmission projects. Interconnection costs are virtually impossible to predict, so that is not a good basis for a new business.

There is no tactical or small-scale solution for this problem. The solution will come only by implementing a coherent capacity/reliability pricing policy. Such a policy is in place in New York, but for other ISO/RTOs it is still on the drawing board or before FERC.

The Network Transmission Pricing Problem

The evolution of the pricing of network-transmission services is the second area where the planning processes of ISO/RTOs can have unintended consequences for new transmission lines. Repayment of the original cost of the transmission system is effected by “network service” tariffs paid by users of transmission services. Typically, load-serving entities then pass on a “network transmission service charge” to their customers. New customers can ask for transmission in one of two ways: network service (the most flexible) or point-to-point service (firm or non-firm).

Under the open-access rules, if there is transfer capacity on the existing system, transmission organizations are required to make that capacity available at designated firm or non-firm tariff schedules. In this construct, a new point-to-point service request within an ISO/RTO is usually not necessary because network service is sufficient.

The emergence of independent transmission projects between control areas creates new challenges and opportunities for network transmission pricing. For the sake of stimulating new, creative, and independent transmission projects—such as AEP’s new backbone for PJM—the overarching policy principle behind network transmission pricing needs to be simple if it is to be effective.

As an example, one need look no further than the development of the interstate highway system in the 1950s that stimulated national economic growth. Before that ambitious plan was hatched by the federal government, farmers in California found it hard to compete in markets in the Midwest and the East because transportation costs were prohibitive. The overall American economy in effect looked much more like today’s American electric system—regionalized, and less efficient than it could be because of transportation bottle-necks.

Prior to its success, the development of the interstate highway system raised many of the same issues churned up today with the development of electric transmission superhighways. When a new interstate highway was proposed, it changed the pattern of usage of connecting state and local roads. Typically, the federal highway fund would pay some “interconnection costs” to finance the expansion of interconnecting roads, but it could not and did not fund claims on all of the potential impacts on state roads.

The bedrock principle behind the interstate highway system was that it generally was productive to increase the carrying capacity of roads between states: It allowed each state to do what it did best, and to trade with other states. Thus, California became a source of produce for the entire country, while agriculture in other states languished because it could no longer compete with California’s produce.

California’s exporters paid a “transmission cost” to get their goods to market, but it was largely a marginal, variable cost (the cost of the transport service), while the cost of the infrastructure itself was socialized across all taxpayers.

Since the interstate system was first developed, much thinking has been done about how best to charge for the benefits of enhancements to the system. The states and the federal government each have a share to pay, and the allocation of costs is a matter of regular wrangling between them. But the bedrock principles—that it is good to have roads with lots of carrying capacity, to monitor and address congestion, and to invest in enhancements wherever they are needed—by now are widely accepted.

The same level of acceptance needs to come to the country’s electric transmission system. The development of ISOs/RTOs is a step forward in getting states out of their pre-interstate highway mode of thinking, but even ISOs/RTOs can fall prey to old-fashioned thinking about how to charge for transmission services.

Network vs. Point-to-Point Service

The most typical, traditional, and ultimately unconstructive form of transmission pricing is “point to point.” To be sure, it occasionally may be economically sensible to charge a specific supplier and a specific customer a specific, project-based fee for moving energy and capacity services between them. But these instances are, and should remain, rare.

The most exciting innovation in the development of ISOs/RTOs is network-transmission service, in which the independent grid operator finds the most efficient way to move energy and capacity services from one area to another without designating exactly which of the thousands of lines it controls will be used for that purpose. To that end, the ISOs/RTOs have developed an elaborate series of rules and regulations governing how the differences in the capabilities of the transmission system will be reflected in energy and capacity prices. Energy prices are now “nodal” (the location-based marginal price principle) and capacity prices are becoming “zonal.”

The ongoing market design issue is how to incorporate substantial new transmission lines that have positive economic impacts and are not built solely for reliability. Should these new lines be seen as “point-to-point” in purpose, or should they be integrated into the overall “network”? The answer to this question has implications for the overall economic efficiency of transmission systems, and implications for cost allocation on the part of those who would use the capabilities of new transmission systems or projects.

First, there can be little doubt that the overall economic efficiency of transmission systems is optimized when point-to-point pricing is minimized. That was the whole point of the development of ISOs and RTOs. Thus, the general rule should be to apply network transmission service whenever possible. But the application of that general rule to new projects is not as simple as it might seem at first.

The laboratory in which the rules are being developed is, at the moment, in the transmission projects between New York and its neighboring control areas, New England and PJM. The most active process for developing reasonable rules is between PJM and NY-ISO.

The Meaning of “Firm” Transmission Rights

As part of its systematic development of rules for independent transmission projects, PJM has created a product called firm transmission withdrawal rights (FTWRs), which it defines as “the rights to schedule energy and capacity withdrawals from a Point of Interconnection … of a Merchant Transmission Facility with the Transmission System. FTWRs may be awarded only to a Merchant D.C. Transmission Facility that connects the Transmission System with another control area. Withdrawals scheduled using FTWRs have rights similar to those under Firm Point-to-Point Transmission Service”2 (emphasis added).

If new projects are to become efficient transmission superhighways, FTWRs should make it possible for any generator in the original PJM footprint to deliver capacity to the DC bus serving the New York market. The exact meaning of FTWRs, however, was the subject of a series of exchanges between PJM and FERC over the Neptune project. These exchanges may be summarized as follows:

1. In early 2005, in a series of orders governing the Neptune project’s PJM interconnection costs, FERC noted that FTWRs had “elements of deliverability” whose extent would be further defined as specific transmission customers sought service to the Neptune bus. At that time, Neptune’s sole customer, the Long Island Power Authority, had not yet selected a PJM generator for service across Neptune.3

2. In its initial responses to Neptune’s emergence (scheduled for mid-2006) as a withdrawal point, PJM proposed that a generator seeking to deliver capacity services to the Neptune bus would have to file a point-to-point service request.4

3. In the summer of 2005, however, PJM also began to develop its transmission enhancement cost-allocation policy. In that effort, PJM proposed that the load being served by Neptune’s customers effectively would constitute load in PJM, and as such would have to bear a share of the PJM regional transmission expansion plan reliability costs.5 Such an allocation of the cost of maintaining the reliability of the network, however, would seem to carry with it a right to use the network’s services.

It is important for the future development of a more competitive power market that this unfolding transmission cost-allocation process in PJM (and elsewhere) not develop into a new form of rate pancaking. An LSE should be able to use a properly permitted, new independent transmission line to purchase energy and capacity in a neighboring control area without a lot of complications. Paying twice for anything in this construction simply will not work to accomplish the task at hand, which is to build more transmission superhighways.

In essence, it should be possible to move the purchasing point of an LSE from one control area to another, as long as the applicable reliability criteria are met. The new transmission project can open a new, wider door to a neighboring control area just as a new superhighway can widen the door for other commerce between the states. The new transmission project’s customers can and should pay for the reliability upgrades needed to maintain the firmness of the product (FTWRs) they are purchasing. In return, the customers should get to choose between network and point-to-point service.6

Seen in this way, an independent transmission line to another control area offers customers a diversification of transmission pricing risk, and as such should be seen as a welcome and security-enhancing development.

A reasonable and coherent policy on the allocation of costs to new transmission entities might look like this:

1. A new transmission project pays for its impact on the grid, as the grid is on the day of interconnection, via its interconnection cost.

2. Once the project is in the grid, it becomes part of the calculus of how much new transmission is needed. The cost of that new transmission is usually covered by transmission enhancement charges that are imposed on transmission owners, who in turn pass them on to load-serving entities (recognizing that these are often the same organization), who pass them on to their customers, the final consumer.

The interconnection cost is, in essence, the initiation fee for access to a regional transmission grid. The ongoing payments for transmission enhancements needed to maintain reli-ability are, in essence, the annual membership fee. With these simple and fair “rules of the road,” the way will be clearer for the development of more inter-regional transmission superhighways.

 

Endnotes:

1. The interstate project may not follow the usual interconnection process for a new independent transmission line. Instead, it may be incorporated into the PJM regional transmission expansion base plan as a long-term reliability project, and be funded via an overall increase in the PJM network service charge. Which financing method is more appropriate—“beneficiary pays” or “everyone pays”—is the subject of ongoing discussions within PJM and before FERC. We believe this particular project should qualify as a long-term reliability project, assuming an expansive, policy-based definition in which reliability includes PJM fuel diversification. Needless to say, this is a complex issue, and another example of how transmission development will continue to take place under investment regimes that include both regulated and market-based principles.

2. PJM Open Access Transmission Tariff, 1.13A, p. 35.

3. See Neptune Regional Transmission System LLC v. PJM Interconnection LLC, 110 FERC ¶ 61,098, at P 31 (2005), reh’g denied, 111 FERC § 61,455 (2005), appeal pending sub nom. Pub. Svc. Elec. & Gas Co. v. FERC, No. 05-1325 (D.C. Cir. filed Aug. 16, 2005); see also PJM Interconnection LLC, 112 FERC ¶ 61,276, at PP 5, 13 (2005). It should be noted that the author is a consultant to the Neptune Project and a principal in the company (Atlantic Energy Partners LLC) that developed the project.

4. This proposal creates some barriers to entry in its own right. If a point-to-point regime is applied in this fashion, potential users of the new transmission project’s FTWRs may not know what their point-to-point transmission costs will be for several years. First, they cannot request point-to-point service to the new projects withdrawal node from the ISO/RTO until the new transmission nodes are in the system, from a studies standpoint. That will happen only after the system-impact studies are completed, or perhaps even later, when the network upgrades that the new project has to provide are finalized. Only then can the ISO/RTO study the point-to-point request into the new transmission project’s source or sink nodes. Then, if there is not enough capacity, the company making the request must cycle through all of the usual feasibility/SIS/facilities studies before it knows the full cost of providing capacity and energy services to its customer. This could take several years.

5. PJM Interconnection LLC, Docket No. ER06-456-000, Filing Letter at 5-6, Tariff Revs. at 1 (filed Jan. 5, 2006). PJM proposes to designate the “sink” end of these projects as “load” areas. PJM did acknowledge that its filing does not address whether such costs ultimately should be paid by the project, by the project’s transmission customers, or by PJM market participants that deliver power to the project’s point of withdrawal.

6. PJM’s FAQs on Neptune indicate PJM’s intention allow is to Neptune’s customers to opt for network integration service into Neptune, or point-to-point service. See Question 38: “b. Transmission service from the source(s) in PJM to the HVDC terminal in PJM. The transmission customer can choose either point-to-point transmission service or network transmission service, depending on their respective circumstances. See response to 44 below regarding those circumstances under which network service may be used to serve external load.” Question 44 asks, “Which type of service (Network vs. Firm PtP) would be applicable in the case where an entity enters into a call option arrangement under a defined indexed value with a generator in PJM, thereby providing that entity with the ability to procure energy from the bulk power market during lower cost hours and/or when the unit is unavailable?” The answers are shown as “A. A customer can use network service for external load that is included as PJM network load. In this case, the customer must designate network resources to support the load. A customer must use firm point-to-point service for load that is excluded from PJM network load. Section 31.3 of the OATT, Network Load Not Physically Interconnected with the Transmission Provider, states: This section applies to both initial designation pursuant to Section 31.1 and the subsequent addition of new Network Load not physically interconnected with the Transmission Provider. To the extent that the Network Customer desires to obtain transmission service for a load outside the Transmission Provider’s Transmission System, the Network Customer shall have the option of (1) electing to include the entire load as Network Load for all purposes under Part III of the Tariff and designating Network Resources in connection with such additional Network Load, or (2) excluding that entire load from its Network Load and purchasing Point-To-Point Transmission Service under Part II of the Tariff. To the extent that the Network Customer gives notice of its intent to add a new Network Load as part of its Network Load pursuant to this section the request must be made through a modification of service pursuant to a new Application.” The FAQs may be found at http://www.pjm.com/planning/downloads/rtep-trans-neptune-faqs.pdf.