Any electricity resource plan should consider various ways to meet end users’ electricity demands at the lowest total resource cost. Conventional upgrades to the existing interregional transfer capability within the WSCC are likely part of such a least-cost plan. The other major alternatives to conventional resource additions are emerging transmission technologies for increasing interregional transfer capability, management of end-use peak loads, energy efficiency and distributed generation. These alternatives are discussed below.

In addition, a least cost plan should have the appropriate mix of utility-scale generation near load centers. Loads will likely differ from the forecast used in this analysis because actual conditions will differ from the assumptions that underlie the WSCC load forecast. These include natural gas and electricity prices, demographic and economic factors, demand-reduction measures and the use of distributed generation. A study of the optimal mix of utility-scale generation resource additions for a few load and natural gas price scenarios is a logical next step for this Western Governor’s work group.

Natural "uncontrolled" power flow on electric power transmission networks, normally, results in less than full utilization of available transmission capacity. One or more transmission lines may be loaded up to their thermal limits while the remaining lines are loaded to levels far below their thermal capacity.

The following provides technology-based solutions, which might increase the utilization of available network transmission lines without violating their thermal limits. These technology-based solutions are in a mature development phase and have been applied on a number of utility networks in the U.S. and in other countries.

FACTS stands for Flexible AC Transmission System. FACTS is a set of controllers designed to provide dynamic control of power transmission parameters, i.e., transmission line impedance, voltage magnitude and phase angle. FACTS uses solid-state switches, of kA and kV ratings, to synthesize controlled currents and voltages that are appropriately injected into transmission network. These injected currents and voltages provide the needed corrections to allow and/or limit power flow on any specific transmission lines in the network. The appropriate application of these controllers, based on their size and location in the transmission network, has provided economically and technically attractive alternatives to building new transmission lines.

Tennessee Valley Authority (TVA) installed a FACTS controller, which is providing dynamic and flexible voltage and reactive power support at their Sullivan substation. The controller is a Static Synchronous Compensator (STATCOM). STATCOM has enabled TVA to defer a new 160 kV transmission line and the need to install a 500 kV/160 kV step down transformer at the Sullivan Substation.

American Electric Power (AEP) installed a FACTS controller. It provides voltage support at their Inez substation and dynamic power flow control at the Big Sandy-Inez high capacity transmission line. The controller is a Unified Power Flow Controller (UPFC). The UPFC has resulted in increase of power transfer capability by 100 MW and a dramatic improvement of the power quality supplied to 2000 MW load area.

New York Power Authority (NYPA) is installing a FACTS Controller to relieve a bottleneck at their Marcy Substation and to provide power flow control on two transmission lines. The controller is a Convertible Static Compensator (CSC). The CSC will increase the total Central-East power transfer capability by 240 MW without adding transmission lines.

Central & South West (CSW, now AEP) installed a FACTS controller to interconnect the asynchronous U.S. and Mexico grids at their Eagle Pass substation. The controller is a Voltage Source Converter-based Back-to-Back (VSC-BtB). The BtB has allowed AEP to avoid building a long 138 kV transmission line. Also, the BtB has provided a reliable electric bridge between the US and Mexico.

DTCR Technology

DTCR stands for Dynamic Thermal Circuit Ratings. DTCR is a methodology to calculate the real-time dynamic thermal rating of transmission circuits. Based on real-time monitoring of actual transmission circuit loading, weather condition (wind speed and direction, ambient temperature), other parameters (line tension, temperature, sag, etc.) a Time To Overload (TTO) window is determined. Typical TTO values allow increases in power transfers of 5 to 15 percent for a few minutes to several hours.

DTCR has been implemented at more than 10 utilities. Below is a brief description of the technical and economical benefits at two utilities.

Use of DTCR technology allowed the Salt River Project to delay a power line for up to five years (about $9 M savings). The Agua Fria-Westing 230 kV line is "critical path" for economical serving the Phoenix metro area. DTCR technology lets Salt River Project use real-time information to determine the line rating. The result is a significant increase in transfer capability, over 90% of the time.

Implementing DTCR technology on underground lines serving a Vancouver suburb has helped BC Hydro to defer for one year the replacement of existing 230 kV cables, for a one-time saving of about $1M. Integrating DTCR technology with BC Hydro energy management system provided BC Hydro with a foundation for maximizing their transmission capacity and making it fully available to the dispatchers.

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The modeling studies in this Conceptual Western Transmission Plan consider two utility-scale generation plans and two gas price forecasts. That is a good first step. To go the next step requires three additional analyses.

First, the plan should evaluate using emerging technology-based solutions to increase existing interregional transfer capability. Otherwise, even the transmission capacity expansion decision will not be least-cost.

Second, the plan should analyze alternative scenarios of West-wide load growth. Peak loads will actually grow in ways that are different from the forecast used in this plan. Economic activity and population growth will be different than forecast. The implementation of end-use load management, energy efficiency and distributed generation will be different than forecast, with differences driven, perhaps, by different retail electric-pricing strategies.

Finally, the plan should contain a sensitivity analysis on the issues of natural gas prices, electricity prices, and load growth. Electricity prices will be driven, in part, by natural gas prices and the two in concert will likely affect load growth, so these two sensitivity variables interact. This joint energy-price/load-forecast sensitivity would result in a minimum of four scenarios, low and high gas price, with associated electricity prices, combined with high and low load forecasts. Alternatively, there could be nine scenarios, with high, medium and low values for gas prices and Western loads. These four or nine scenarios should be analyzed for the appropriate mix of utility-scale peaking, intermediate and base-load generating resources. These analyses could be conducted using the GE-MAPS, Aurora, Henwood (?) or other West-wide models.

Page last updated 10/10/1999