The latest dispute over PJM’s bidding rules has raised the level of uncertainty in organized electricity markets. Efforts at reform have created a market structure so jumbled that it can’t produce...
The Too-Perfect Hedge
Congress gives FERC an impossible task: Craft long-term transmission rights to save native load from paying grid congestion costs.
toward compliance three months ago, when it issued a notice of proposed rulemaking (NOPR) governing long-term transmission rights (LTTRs) in “organized electricity markets” (defined as the day-ahead markets run by RTOs that feature LMPs and FTRs). Yet it remains unclear how FERC should attempt to carry out this near-impossible assignment.In fact, the task appears so daunting that, rather than craft a clear set of rules, the commission has chosen instead to lay out a bare outline of eight so-called “guidelines” to govern the process, and then punt the question back to the RTOs. This tactic only has heightened the confusion, as the guidelines appear so vague and internally inconsistent as to permit virtually any interpretation. (See Docket No. RM06-8, Feb. 2, 2006, 114 FERC ¶61,097, plus industry comments filed through April 3, 2006.)
Above all, the new law appears vague, lacking adequate definition on a number of points, as does FERC’s proposal:
1. Duration. How long is long-term?
2. Physical vs. Financial. Must LTTRs be physical, or will it suffice simply to lengthen the one-year financial rights already offered by RTOs?
3. Subsequent Modification. If the hedge, once allocated, “should not be modified,” as FERC insists (except upon extraordinary circumstances), then isn’t the LTTR in reality a physical carve-out that could distort RTO markets?
4. Mitigating Impacts. Again, if physical, then how can FERC mitigate (“balance”) the adverse impact on RTO market participants that will occur because of fewer available short-term FTRs?
5. Revenue Shortfalls. If financial, should RTOs make LTTRs fully funded, and if so, then who backs up any revenue shortfall?
6. Priority Issuance. Should LSEs with native-load service obligations enjoy priority in allocations or auctions of LTTRs? Even if the obligation derives from contract rather than operation of law? How long a term is required for such contracts?
7. Sham Transactions. If priority is warranted, then do LSEs lose priority if they lose load or contracts? Can they assign excess LTTRs to lower-priority retailers, or resell LTTRs at a profit? If so, wouldn’t that encourage sham transactions, requiring RTOs to scrutinize or “police” contract claims?
8. Conflicting State Laws. How should FERC deal with retail access states that may conduct auctions to reassign the native-load service obligation (Ohio, perhaps?), or impose term limits (3 years or so) on contracts purchased through statewide gen supply auctions, such as Illinois or New Jersey?
9. Simultaneous Feasibility. If initial LTTR allocations take place, as FERC proposes, without requiring LSEs to participate in auctions, how can RTOs assure simultaneous feasibility of all issued FTRs?
10. Participant Funding. If RTOs should allocate extra LTTRs to those who fund grid upgrades that increase availability of FTRs, as FERC suggests, then how do RTOs reconcile two conflicting ideas: (1) That LTTRs must identify a particular source and sink, versus (2) that RTOs issue FTRs and verify simultaneous feasibility without regard to actual grid usage or schedules, because economic theory teaches that Simultaneous Feasibility is assured if the grid topology assumed in the FTR allocation matches the topology employed in the security constrained dispatch and setting and