Environmental groups are ignoring issues like relatively high interconnection costs for solar and wind projects in pushing Virginia Electric and Power d/b/a Dominion Virginia Power to include more of these projects in its latest integrated resource plan, said a company witness in Oct. 9 testimony filed at the Virginia State Corporation Commission.
Virginia Electric and Power is a subsidiary of Dominion Resources (NYSE:D).
James R. (Ronnie) Bailey, the Manager-Planning and Strategic Initiatives in the Electric Transmission Department of Dominion Virginia Power, was one of the company witnesses that supplied rebuttal testimony in the commission’s ongoing review of this year’s version of the integrated resource plan. The purpose of his rebuttal testimony was to respond to the direct testimony of Karl R. Rabago on behalf of the Chesapeake Climate Action Network, Appalachian Voices, Virginia Chapter of the Sierra Club, and the Natural Resources Defense Council as it relates to integrating solar generation into the Dominion Virginia Power transmission grid.
Bailey noted that there are 31 active solar requests in the PJM Interconnection queue in Dominion North Carolina Power‘s service territory. Dominion North Carolina Power is the d/b/a name for Virginia Electric in that state. The 31 active requests require 31 separate points of interconnection to the transmission system, and each point of interconnection will require its own switching station. Further, because these solar farms are located within relative close proximity to each other with some on the same transmission line, they also require a complex anti-islanding scheme to ensure safety and reliability to the transmission system, Bailey pointed out.
With renewable energy and especially solar the utility is seeing more transmission points of interconnections as compared to traditional large scale generation. This tends to drive up costs on solar as compared to other large scale plants. For example:
Traditional Large Scale Generation
- 1,588 MW capacity combined-cycle gas plant (Dominion’s proposed Greensville gas plant in Virginia cited as example)
- $26.3 million interconnection cost for switching station
- Cost per kilowatt (kW) = $16.56/kW
Large Scale Transmission Connected Solar Farm
- 80 MW solar connecting to 230 kV (example from PJM queue request)
- 56 MW Capacity (80 MW Energy) – Assuming a 70% capacity factor
- $7.25 million interconnection cost for switching station
- Cost per kW = $ 129.50/kW
Large Scale Transmission Connected Wind Farm
- 300 MW Wind farm connecting to 230 kV (example from PJM queue request)
- 39 MW Capacity (300 MW Energy) – Assuming a 13% capacity factor
- $6 million interconnection cost for switching station
- Cost per kW = $153.80/kW
At a high level, the cost per point of interconnection for solar and wind versus a large scale combined-cycle natural gas plant is at a minimum eight times as much, Bailey wrote. It should be noted also that regardless of the size of the renewable source connecting to the transmission grid, the interconnection costs are averaging around $6 million per request.
In addition, as mentioned before, with solar requests the utility is seeing that there are significantly more points of interconnection over a shorter area. This not only increases costs, but also becomes an issue operationally – more points of interconnection mean more equipment and locations for system operations people to monitor, as well as more equipment failures long term.
Islanding is a condition where grid-connected generation becomes disconnected from the system and can operate in an island serving the local network. This condition can result in a number of potential hazards, Bailey said. Essentially, the local network is being energized by this generation when it should be tripped to avoid damage to equipment as well as safety. Anti-islanding schemes are designed to detect this condition and immediately trip this generation off-line before damage and safety issues can occur. These schemes require reliable and secure communication across a large area and sometimes can include a complicated tripping matrix to determine the islanding condition and deliver a trip signal remotely to the local generation. These types of schemes are more challenging and typical for small scale generation such as solar when there are multiple requests in a small geographic area, he noted.
The effective capacity of solar projects is a contested issue
Another company witness who addressed points made by Rabago in Oct. 9 testimony was Robert G. Thomas, the Director-Energy Market Analysis & Integrated Resource Planning at Dominion Resources Services.
Thomas said that for new intermittent generation resources such as solar photovoltaic that do not have a history of operation during the peak hour(s), PJM historically has assigned a dependable capacity rating of 38% of the installed (i.e., nameplate) capacity of the facility in question. The 38% figure is based on a three-year rolling class average capacity factor rating during the summer peak hours. Put another way, PJM has determined that 38% of the nameplate MW capacity of new solar facilities is available at the time of summer peak and is therefore considered dependable for servicing that peak. This also has allowed that facility to bid up to 38% of its nameplate rating into PJM’s Reliability Pricing Model (RPM) capacity auctions, which are conducted annually in order to assure reliable operation of the PJM grid.
The solar facilities incorporated in the Dominion integrated resource plan were modeled using a dependable summer rating of approximately 45% of nameplate. This rating is based on the company’s internal information and is clearly in excess of the summer rating historically offered by PJM, Thomas noted.
In his testimony, Rabago asserts that rather than using capacity factor value, a more meaningful measure of the value of solar PV is effective load carrying capacity (ELCC), which represents a measure of the marginal value of an additional resource to the reliability of the system. “It is true that ELCC is one measure of reliability but, in my estimation, it is questionable as to whether it is more meaningful than the capacity factor value technique,” Thomas wrote. “In fact, PJM has and continues to utilize the capacity factor value technique in assessing the dependability of solar PV and other intermittent generation resources, as evidenced in its Manual 21.
“Additionally, PJM has recently revised its RPM capacity market rules to introduce a new product known as Capacity Performance. Under these revisions is recognition of the performance of supply- or demand-side resources during winter peak periods. Given that solar PV resource generation output is quite low during winter peak hours, the overall dependable capacity rating (summer and winter) of these resources is likely to be reduced regardless of the measure used (i. e., capacity factor value or ELCC). Under this new Capacity Performance Product, PJM estimates that the dependable rating of solar PV resources will now be -20% of the nameplate capacity of the facility in question, rather than the 38% described above.
“As we learn more about the realities of integrating large quantities of solar into the grid, risks that are not now apparent may come to light. For example, it is not unreasonable to anticipate that as more and more land is utilized for solar PV development, public opposition could increase commensurate with that of any other type of generation resource. And grid stability impacts and costs could introduce operational and financial risks not now fully apparent. For these and other reasons, we cannot assume that solar PV is lower risk across the broad spectrum of planning scenarios and possibilities.”