February 2006

FTRs: How Square is the New Deal

by Roger Feldman  --   Bingham, Dana L.L.P.
(originally published by PMA OnLine Magazine: 2006/04/01)
 

In the beginning when deregulation spelled a new deal for merchant power generators, transmission constraints were something disaggregating utilities had to deal with so the new functionally divided system would work. As a result of the “functional unbundling” which it mandated, network and point to point transmission were to be available to all would-be power suppliers utilizing the grid, pursuant to utility fell open access tariffs (“OATTs”). After finding a few years later that despite its efforts discrimination and congestion lumps nevertheless remained in the transmission oatmeal, FERC Order 2000 began the gestation of supervisory RTOs, to ensure that the FERC’s newly mandated market mechanisms handled transmission congestion and afforded adequate market monitoring.

Most of the RTOs and ISOs subsequently formed and now make use of Locational Marginal Pricing (LMP) to measure the cost of congestion between transmission points and “Financial Transmission Rights” (“FTRs”) designed to enable market participants to hedge their volatile transmission costs, which reflect the impacts of deregulation. It has turned out, however, that FERC’s highly economically calibrated FTR model also resulted in the new improved markets not offering the old one did, this has lead to further reexamination of how FTRs should be made available described below.

All of the mandated institutional change did not alter transmission capacity to deal with the market design new model FERC introduced: transmission constraints remained and multiplied. Indeed, the system was further stressed by new change. As the NOPR contained in Docket No. RM06-8-000 (Feb. 2, 2006) stated “Market participants (are), seeking to obtain rights that replicate the transmission service that were available prior to the formation of the organized electricity market and remain available today in regions with organized electricity markets. The principal concern of these market participants is “the inability to obtain a fixed price long term level of service under pricing arrangements that hedge the congestion cost risk that they face in electricity.” (emphasis added)

Why the sudden insight by FERC of the possible fallibility of the Commission’s market structure mechanics?

The answer is 1233(b) EPACT, which added Federal Power Act Section 217(b). It directs the Commission to enable load serving entities to secured firm transmission rights (or equivalent tradable or financial rights) on a long term basis for long term power supply arrangements made, or planned, to meet such needs. (The translation of which seems to be: “fix the system so utilities can function on a long term contract basis in RTOs”)

To this Congressional directive, in lengthy NOPR, the Commission appears to have replied:

• We will give preference to utilities which have long term service arrangements
   

• We will set guidelines so that the Financial Transmission Rights (“FTRs”) to achieve this result can be made available by different RTOs in ways which can accommodate regional differences.
   

• We are doing this because we want to increase the market certainty so that both needed new transmission investments and long term power-supply arrangements will be made.

All of which is good public policy, until we get to the point where the rubber meets the road; paying for transmission improvements:

“The Commission’s policies that market participants that request or support an expansion or upgrade . . . must be awarded long term transmission right for the incremental transfer capacity created by the expansion or upgrade “- equal to life of the new facilities.

Further, under the NOPR traditional “native load” preferences will continue to prevail. One of the eight guidelines for RTOs proposed is that: “Load serving entities with long term power supply arrangements to meet a service obligation must have a priority to existing transmission capacity that supports long-term financial transmission rights required to hedge such transactions.” FERC indicates that it wishes FTR’s to be available to both those financing their service obligations and also those who seek transmission to finance investments in new transmission requirements or power purchase contracts. But this may not always be possible. In, either case, does not seem too cynical to suggest that the cost of FTRs will be tacked by transmitting load serving utilities into the bills of would be merchant suppliers. If this is the case, it does seems reasonable to inquire: how will this affect new renewable projects built in remote areas. How it will affect the negotiating balance of those classes of “merchants” providing new lines which interconnect with existing systems? How it affects those classes of entrepreneurs proposing to offer transmission conservation to PTOs and utilities, via technology enhancements over existing lines and realize a return on the valuable service offered.

Congress has issued, essentially, a call to order in aspects of the transmission field. FERC has responded, with some sensitivity to regional requirements. Innovation, however may not receive as square a deal as the utility beneficiaries of the new deal for FTRs under the new NOPR. 

ROGER FELDMAN, Co-Chair of Andrews Kurth LLP Climate Change and Carbon Markets Group has practiced law related to the finance of environmental and energy projects and companies for 40 years.  In particular, he has analyzed and executed a wide variety and substantial value of project financings.  He chairs the American Bar Association’s Committee on Carbon Trading and Finance, serves on the Board of the American Council for Renewable Energy, and has been a senior official in the Federal Energy Administration.  He is a graduate of Brown University, Yale Law School and Harvard Business School.