The Key to Maximizing the Value of Your Own Transmission System
Have you ever noticed when automobile advertisers are touting their latest and newest toys, much is made of the monthly lease payments but rarely do you hear about the actual cost of the car were you to buy it outright? At the end of the lease, you had the privilege of driving the vehicle, but you never actually “owned” the car. Transitioning that concept to transmission, many load serving or transmission dependent customers have been paying for transmission facilities owned by incumbent transmission providers for decades through grandfathered agreements and the Open Access Transmission Tariff (OATT) for the privilege of driving across those wires but never owning any assets. Wouldn’t it be nice if there was a way to have someone send you a check for your facilities for a change? The key to unlocking this mystery can be found in how transmission facilities are qualified for inclusion in the region where the electric utility’s load is located and how a utility can make modifications to their system to leverage their current transmission assets. There are five easy steps to follow:
The first step is to UPDATE RECORDS. In order to file an accurate revenue requirement for transmission assets, an electric utility must have accurate knowledge of their existing system. This needs to include knowledge of what is in the field and what is in the accounting records. If those don’t match then utilities should make the effort to synch those two areas. When it comes to field data, having detailed records of each element in the field can also help with facility rating determination and other potential NERC requirements.
Once the records are in order, take time to know the landscape. For electric utilities who are procuring transmission service from a company that has their own OATT, Section 30.9 is the primary vehicle to get credits for qualifying facilities. For electric utilities located within a Regional Transmission Organization, like PJM, MISO or SPP, learn the rules for what is considered “transmission” for tariff purposes. The standard for counting a facility as transmission can take many forms ranging from the FERC Seven-Factor Test to the number and types of customers on a circuit to a particular voltage level cutoff to a “contiguous path” standard. Also, just because a facility qualifies as a Bulk Electric System element under the NERC definition does not mean that it qualifies as a transmission element under the OATT, and visa-versa.
Next in the decision process is to ASSESS THE BENEFITS AND RISKS. The main benefit of placing qualifying facilities under the OATT is revenue recovery for existing transmission assets that qualify under the transmission provider rules. The other benefit comes from the return on equity available when assets are placed under the control of a RTO. At present, the ROE in most RTOs is over 10.5% (and some RTOs have ROEs as high as 12.25%), and even if that ROE is reduced, the return is still a plus when compared to most public power/non-profit entities weighted cost of capital. Risks can take two forms: impacts of qualification of existing facilities as a result of grid expansion and modification, and additional NERC compliance exposure. Of course, the cost of becoming a Transmission Owner in a RTO will need to be factored into the decision.
After weighing the options and deciding to move forward, it’s time to LOOK FOR OPPORTUNITIES. First, look for places on the existing system where normally open points exist and determine if it is feasible to close those points and created looped network facilities. Just because it is technically feasible does not mean that the lines as designed can handle significant loop flow. Power flow analysis can be performed to determine how the electric system will respond under multiple contingency conditions. If no overloads or voltage problems are identified, then it is time to move forward with the facilities qualification process. If problems are revealed then the electric utility may want to determine what needs to change with the existing facilities before closed loop operation occurs. Next, the electric utility should review the reliability problems identified by the regional entities’ annual transmission planning process and see if there are opportunities to loop in the electric utility’s lines that can resolve local issues. In many instances, the transmission provider or regional transmission organization does not have the granularity of non-looped or lower voltage facilities in their power flow models, so they do not look at lower voltage solutions to mitigate known problems. Conducting an independent power flow analysis with the electric utility’s local facilities included may reveal solutions that others do not or cannot identify.
Another tool in the box is the use of LOCAL PLANNING CRITERIA to reflect the unique nature of your electric system. In many cases, the needs that drive transmission expansion are more than the typical NERC Transmission Planning or TPL criteria. Sometimes, grandfathered power supply and transmission agreements include language related to maintaining a particular voltage or power factor at the point of delivery. In order to maintain adequate voltage downstream from the POD, additional facilities or equipment may be needed. The inclusion of minimum nominal voltage or maximum voltage drop criteria at the end of radial transmission circuits can be used to encourage the development of radial-to-looped conversion to meet such a criteria. Many utilities employ a load-at-risk criteria to address potential reliability concerns. Load-at-risk can take several forms. For example, some companies look at secondary feeds or looped service to feeders when the load is projected to exceed a specific MW threshold regardless of the length of the circuit where the load is located. Another option is the use of a MW-mile criteria, to be able to capture those lines where circuit length may expose low load but high priority service.
The decision to step out and join the ranks of the network transmission facility owners does have some risks that need to be addressed, including operational control questions, NERC compliance responsibilities, and joint planning requirements. If an electric utility decides to move forward and place their qualifying facilities under a RTO tariff then that means increased communication requirements with the RTO. Outage coordination now becomes a coordinated effort through the RTO. The RTO Reliability Coordinator now has greater visibility into the individual electric utility’s system and has the authority to direct those utilities to take action at their directive, in accordance with NERC requirements. Speaking of NERC requirements, there are certain requirements that come with the privilege of being counted as a Transmission Owner (TO) in the NERC Functional Registration. It is important to develop in-house expertise or hire compliance experts who can assist the electric utility with unraveling the mystery of NERC Compliance as a TO. The planning of transmission facilities now involves greater coordination due to loop flow impacts across the electric utility’s lines, modeling requirements to make sure that all of the electric utility’s qualifying facilities are included, and assessing the impact of proposed solutions by others on the individual electric utility’s system.
Finally, get the APPROPRIATE REGULATORY APPROVALS. It is important to complete several activities, including understanding the requirements for facilities qualification for either 30.9 credits or revenue sharing agreements, filing of transmission revenue requirements with FERC, and the negotiation of revenue sharing agreements with existing Transmission Owners who share a common pricing zone.
Just like the lease versus buy decision for modes of transportation, there are benefits and costs to both and it is important to carefully weigh those factors so that the electric utility can make a decision in which they are both confident and comfortable. Having a coordinated approach between the transmission planning, accounting, compliance and regulatory functions of the electric utility to properly assess those factors can provide long-term reliability and economic benefits for consumers for years to come.
For more information or to comment on this article, please contact:
John Chiles, Principal | CONTACT
GDS Associates, Inc. – Marietta, GA
Also in this issue: Utilities are Toughening Up to Improve Resiliency in the Face of Emergencies