Common development wisdom characterizes portions of the U.S. transmission system as antique and the generation interconnection study and queue process, especially for renewable power as, at best, opaque. As energy lawyers, charged with attaining interconnection and transmission rights for developing generation projects – often in challenging locations – we appreciate how engineering drives regulatory and contracting solutions to difficult interconnection problems such as costly network upgrades paid by the project. Without cost-effective and timely solutions, interconnection issues can wreck a project’s timeline, upset underlying power purchase and other material agreements, disturb financing expectations and, ultimately, threaten a project’s overall viability.
One potential solution to high-cost network upgrades warrants attention: achieve the interconnection through transmission re-rating work, which can be performed ahead of schedule and below the cost of the planned network upgrades while maintaining reliable transmission operations. Not a bad result.
Several Transmission Owner/Operators (“TO”) have established a multi-step process by which generation facilities, including renewable energy projects, may request interconnection to the transmission grid. First, the project submits an application for interconnection, after which it is assigned a “queue” position. The generation project provides information including a facility one-line diagram detailing proposed interconnection points, voltage levels, thermal ratings, generator nameplate and other data. The transmission provider then conducts a series of studies, paid for by the project by agreement. Projects are often required throughout the study process to make certain financial deposits or demonstrations of control over land necessary to construct the generation facilities.
If these deposits or demonstrations of control are not made, the project’s application may be withdrawn and the project’s “queue” position eliminated. Certain transmission providers may simultaneously study several projects requesting interconnection, grouped geographically as a “cluster”. Clustering can be helpful but may also further complicate matters for each individual project seeking timely, cost-effective interconnection. For example, if a member of the cluster decides to forgo its request, the cost to the remaining members associated with needed network upgrades may increase significantly. These costs also may go away entirely, however, if the upgrades are no longer needed due to the exiting project’s capacity leaving the cluster.
TOs generally conduct a preliminary interconnection system impact study (“PSIS”) to estimate the cost of any network upgrades necessary to reliably interconnect the generation facility. Depending on the results of the PSIS, the project may then undergo some form of definitive interconnection system impact study (“DSIS”) which is similar to the SIS and designed to more specifically estimate the cost of network upgrades for which the project will be liable. If the project agrees with the findings and, based on the costs identified in the DSIS, wishes to proceed with interconnection, the TO will commence a facility study (“FS”). The FS will further detail the costs of the required upgrades to the physical interconnection facility. If the project elects to proceed, the project will then negotiate a Generation Interconnection Agreement (“GIA”) with the TO. If the parties cannot agree on terms in the GIA, the project may request termination of negotiations and request that the TO submit the unexecuted GIA to FERC for resolution or initiate dispute resolution procedures under the TO’s tariff.
Often generation projects – including renewable projects – stumble during the impact study or even the GIA negotiation phases over the interconnection costs, timing delays, and potential changes to equipment location and nameplate rating posed by the TO’s proposed network upgrades.
If so, the developer and its counsel should dig deeper. The TO may be correct given its traditional system impact analyses, but the project should ask itself whether such potential upgrades are truly required to interconnect the specific project. The project should consider whether certain upgrades might be driven by extraneous TO considerations or based on static study methods. The project should collaborate with the TO to suggest well-founded, less costly and more timely solutions. One solution is to study – and possibly re-rate – the existing transmission line capacity, which might optimize the existing system and obviate the need for costly upgrades or interconnection delays.
An example drawn from experience:
A wind generation facility was being constructed in a particular region of the United States. After various impact studies, the project was initially going to be limited to interconnecting only a portion of its nameplate capacity until expensive network upgrades could be completed at the project’s expense. Need for these upgrades was based primarily on potential transmission thermal limitations that could occur in very limited circumstances. Construction of the proposed costly network upgrades was estimated to take several years – a material blow to the project. Initially interconnecting a portion of the project’s planned turbines to allow for upgrades, furthermore, would have negatively impacted other contracts and schedules. This type of “phased” interconnection also could have disrupted the full nameplate assumptions underlying existing off-take arrangements.
After several months of cooperative effort, the project, the balancing authority and the TO determined that a relatively simple and low-cost transmission line re-rate could be performed to solve the thermal constraint and, importantly, obviate the need for the significantly more extensive network upgrades initially proposed.
In addition, depending on timing requirements, all turbines could be interconnected at one time (satisfying the off-taker) so long as special control systems were in place to automatically reduce output during the transmission re-rate work. Specifically, a system could be put into place to prevent against thermal limitations occurring during the line re-rate work. The project also could agree to install equipment providing for automatic power output limitation at a certain MW level, automatic output breaker tripping capability, and/or TO circuit breaker control to curtail the project’s output for reliability purposes.
Once interconnected, the re-rate work was performed well ahead of schedule and at a fraction of the cost of the planned upgrades, all without negatively impacting reliability. This creative re-rate solution unlocked access to already existing capacity that otherwise would have gone unused. The solution allowed for the project to meet its obligations under its off-take agreements in a timely manner and at a lower cost.
Dynamic line rating is not a novel approach to addressing reliability issues. TOs determine a maximum conductor temperature for each transmission line that sets the maximum transfer capacity. TOs often rate transmission lines with a fixed (static) rating based mainly on conductor and weather conditions. TOs often use worst-case assumptions calculated years or decades ago to set transmission line thermal limits, including record temperatures, low wind speeds, and failing conductors.
Technology innovations have increased the ability of TOs to maximize transmission line capacity without costly and time consuming upgrades to accommodate viable generation interconnections. Specifically, a transmission grid’s power transfer capacity is not constant and is primarily controlled by three elements: stability, voltage limits, and thermal ratings. As the Valley Group recently stated in its paper Dynamic Line Ratings for Optimal and Reliable Power Flow, “thermal/dynamic line ratings represent the greatest opportunity to quickly, reliably and economically utilize the grid’s true capacity.”
Dynamic ratings apply here because transmission conductors have “thermal inertia”; thus, taking time to change temperature. Because of thermal inertia, a TO often has ample time, under exceptional system events, to determine if and what operator intervention is necessary under these exceptional situations. TOs may be able to utilize this and other assumptions to re-examine the maximum available capacity for their transmission lines under specified conditions and thus find room for new generation, including renewable projects.
Moreover, in recent FERC proceedings, parties have identified optimization studies and re-rating as viable alternatives to costly upgrades, especially for alternative power. For example, the April 12, 2010, ISO-RTO Council White Paper, Variable Energy Resources, System Operations and Wholesale Markets, indicated that SPP has “explored whether to re-rate constrained transmission lines to allow more wind power onto the lines.” Because wind generation is primarily at off-peak times and that the transmission carrying capability is rated at peak times, it is thought that more wind generation potentially could be carried on transmission paths than conventional rating criteria would suggest.
ISO-NE also recently filed comments in the FERC’s rulemaking effort, Integration of Variable Energy Resources (“VER”), Docket RM10-11, responding to a question regarding how have redispatch and curtailment practices changed with increased numbers of VERs. Supporting financial incentives for dynamic line rating investment by TOs that allow a better understanding of real-time transmission capability, ISO-NE responded:
“Redispatch and curtailment practices that depend on static line ratings can artificially limit the usable energy from VERs. Dynamic Line Rating (DLR) technologies facilitate the integration of VERs (such as wind energy) into the existing transmission grid as well as onto new transmission lines. Reliable DLR technology takes into consideration real time weather conditions, particularly wind variability, along the transmission line, and provides the operator with a line rating in real time that reflects actual versus assumed static weather conditions.”
In the majority of the time, DLR allows for more transmission capability over the same line because the actual weather conditions are more favorable than those assumed. Specific case studies exist to support this finding. This is particularly true in case of renewable energy, especially wind farm generation. A transmission line connected to a wind farm is more likely to see more wind than that assumed when the static rating was established.1
We agree: line re-rating is an important tool with which to navigate interconnection troubles.
About the Author
Gregory K. Lawrence is a partner in the Energy and Commodities (E&C) advisory group of the law firm Cadwalader, Wickersham & Taft LLP. Mr. Lawrence focuses his practice on regulatory proceedings, projects, negotiations, enforcement and agency litigation relating to the wholesale and retail electricity and natural gas industries. Mr. Lawrence would like to thank Terence Healey, special counsel, and Ben Chesson, associate, with Cadwalader’s E&C advisory group, for their significant contributions to this article.
1 Other commenters urged increased deployment of Phasor Measurement Units and other smart grid technology not only to enhance reliability but also to enable more efficient use of the grid, for example, through a switch from static to dynamic line ratings.
