The common aphorism is that electricity flows along the path of least resistance. But that aphorism is just the shorthand way of describing the way electricity flows along all available paths, loading those available paths such that the marginal losses on the various paths are the same. A scheduled transaction from Pittsburgh to Philadelphia will change the loading of the lines in Tennessee and Ontario, maybe not much, but at least an amount that can be calculated. Of course, loading lines in Tennessee or in Ontario will change the loading on the PJM lines between Pittsburgh and Philadelphia. The lines in Tennessee and Ontario can be considered to be parts of parallel paths for moving electricity between Pittsburgh and Philadelphia.
It should be noted that the loading of lines in one region changes the loading of lines in another region, not necessarily increasing the loading, but changes the loading. For instance, moving electricity from Pittsburg to Philadelphia loads lines from west to east. If before this movement Ontario had been moving electricity from east to west, the Pittsburgh to Philadelphia transaction would tend to lower the loading on the wires in Ontario. Thus, Ontario would benefit from the parallel path flow associated with a contract to move electricity from Pittsburgh to Philadelphia.
The effect of a Pittsburgh to Philadelphia transaction on Ontario is part of a paradigm known as the “Lake Erie Loop Flow.” A search of the FERC electronic library for 2009/2010 reveals 80 different documents with the term “Lake Erie Loop Flow” in several different dockets, including one docket (ER08-1281) that is effectively on the results of market manipulations associated with the “Lake Erie Loop Flow.”
When I published my first paper, “Tie Riding Freeloaders–The True Impediment to Transmission Access,” Public Utilities Fortnightly, 1989 December 21, I was concerned that the contract path methodology would reward those transmission owners who were aggressive in signing transmission contracts to the detriment of the Ontario’s and the Tennessee’s in the above Pittsburgh to Philadelphia transaction, that is, the other transmission owners who were supplying the parallel path.
During the 1990s, the General Agreement on Parallel Paths (GAPP) proposed a sharing of wheeling revenue among the transmission owners just to the west and south of PJM. GAPP only dealt with wheeling revenue. A direct sale by one of the participants into PJM did not produce wheeling revenue and thus was outside the settlement provisions of GAPP. The GAPP experiment lasted about three years. GAPP contrasted with my proposal that the transmission owners cash out unscheduled flows on a real time, geographically differentiated basis.
About the time of “Tie Riding Freeloaders”, El Paso Electric Company built a new high voltage (345 KV) transmission line that roughly paralleled an existing low voltage (115 KV) transmission line owned by Plains Electric Generation & Transmission Cooperative (now a part of Tri-State Generation and Transmission Association). The lower impedance of the El Paso line resulted in substantial amounts of Plains electricity flowing on the El Paso line instead of on the Plains line. El Paso sought to obtain revenue from Plains for the loop flow that was occurring on the network. Plains called the concept Vampire Wheeling and fought the El Paso claim for compensation. The issue was eventually settled in a transmission planning forum.
Twenty years later the claim of Vampire Wheeling has re-arisen, but with the name of transmission cost allocation. Owners of new high voltage transmission to be built in the footprint of large RTOs are seeking an investment driven revenue requirement that will be paid by all parties within the RTO footprint, whether or not the parties have agreed to the line or believe that they will benefit from the line.
The most egregious example of this unfairness is MISO relative to Michigan. MISO transmission owners are planning major transmission lines to move electricity (much of it generated by wind) from the Great Plains to the Midwest, to the part of the MISO footprint that is south of Michigan but does not include Michigan. Most of the electricity is likely to be sold to utilities even further east along the Atlantic Seaboard. The current plan is to socialize the cost of the transmission lines by requiring all customers in MISO to pay based on their retail load. Michigan objects for several reasons, including
- Michigan’s law that obligates Michigan utilities to source a large amount of wind generation in-state.
- Much of the wind generation will be going on to PJM and then to the East Coast, without Michigan being on the path.
- Though Michigan is currently an integral part of MISO, a situation that will soon change when FirstEnergy changes from being part of MISO to being part of PJM, making Michigan connected to the rest of MISO only through PJM.
I believe that a suitable alternative approach is to cash out on a real time basis all unscheduled flows of electricity between and among the transmission owners, with the RTO’s frequently being treated as the transmission owner for those lines that have been socialized. The price differentials across a transmission system would reflect the marginal line losses. Since marginal costs are greater than incremental costs, the burdened system would earn greater revenue than it would incur in line losses. Conversely, since marginal costs are less than decremental costs, the paying system would pay less than the line losses it saved by the loop flow on the neighboring system.
Reliability issues would be addressed by having the prices respond appropriately. When lines are congested, the marginal line losses nominally increase, resulting in greater price differentials across the congestion point. Similarly, when generation plants are strained, then all prices would increase.
In the Plains/El Paso example, the differences between the scheduled flows at the interfaces between the two utilities would have real time prices that change frequently. The differences between scheduled and metered flows would be priced, with one utility effectively paying the other for fuel at each location, at least most of the time. When the generation systems become strained, the prices would together float up when there is a shortage and float down when the constraint is minimum load conditions, such as those I discussed in
- “Renewable Electric Power—Too Much of a Good Thing: Looking At ERCOT,” Dialogue, United States Association for Energy Economics, 2009 August; and,
- “A Pricing Mechanism To Facilitate Entry Into The FCAS Market: Comments Of Mark B. Lively, Utility Economic Engineers,” Investigation Of Hydro Tasmania’s Pricing Policies In The Provision Of Raise Contingency Frequency Control Ancillary Services To Meet The Tasmanian Local Requirement, Office of the Tasmanian Economic Regulator, 2010 July 9.
The prices at the various interconnection points would disperse when the lines were constrained.