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FERC "Reforms" RTO Credit Rules, Increases Costs to End Users Email This Story October
Under the guise of reform, FERC issued an order on RTO credit policies which
will increase end users' costs for generation service by millions of dollars annually
Chief among FERC's new mandates is that RTOs shall file tariff revisions to establish
billing periods of no more than seven days and settlement periods of no more than
seven days after the issuance of bills. This will mainly impact customers in the
New York ISO and the California ISO which had not independently moved to weekly (or
more frequent) invoicing. The Commission stopped short of requiring daily billing.
The New York PSC, New York Consumer Protection Board, Multiple Intervenors, and New
York Transmission Owners all opposed weekly settlement, citing the costs that it
would impose on retail customers (Matters, 3/30/10). Indeed, a NYISO report found
that weekly settlement would cost end users $6 million annually, while providing
wholesale suppliers with $38 million in annual benefits. The $6 million cost, New
York Transmission Owners noted, takes into account estimated benefits to loads from
"However, stakeholders, representing the interests of consumers, demonstrated that
those off-setting savings were significantly overstated," Transmission Owners said,
reporting that the total increase in financing costs to end users, absent the offsets,
will be $20 million annually.
The New York PSC argued that because the NYISO's credit metrics are already so robust,
weekly settlement would provide a de minimis decrease in risk. The New York PSC
succinctly stated, "[c]learly, weekly invoicing in New York would increase retail
rates, but there is no evidence specific to New York that risk reduction benefits
would equal or exceed these costs."
The rate impact from weekly invoicing has been shown in PJM, where Maryland distribution
utilities have sought millions in additional Standard Offer Service cost recovery
from ratepayers due to the move to weekly billing. At Baltimore Gas & Electric,
the cash working capital cost of providing SOS service to residential customers alone
increased 250% due to PJM weekly billing (Matters, 3/31/10).
"The New York retail market is unique," the New York PSC continued. "Unlike its
neighboring markets, New York's retail market has numerous competitive suppliers
(Energy Service Companies, or ESCOs), which serve more than 50% of the State's retail
sales. By contrast, the Pennsylvania, New Jersey and Maryland (PJM) market has few
retail suppliers, and those few serve largely non-residential customers. Increasing
the costs to LSEs for weekly invoicing, especially with doubtful offsetting financial
benefits, could have a direct and negative impact on the retail competitive market
in New York. ESCOs, like other LSEs, would incur increased working capital costs
and increased operational costs, which could pose a barrier to entry and which could
cause some ESCOs to exit the New York market. These cost increases may negatively
affect the well-established competitive retail energy market in New York," the New
York Commission said.
The California ISO had noted that moving to a weekly billing standard would not result
in significant benefits as it would reduce aggregated outstanding liabilities by
only an additional 10 percent.
In its order, FERC claimed that, "[w]hile short-run working capital costs may be
shifted, the result is that the overall cost of default will be lower for every market
participant." While citing a PJM and ISO New England analysis, FERC did not cite
any study supporting its conclusion that benefits would accrue to customers in other
RTOs, especially considering the other robust credit reforms it is implementing and
the credit rules unique to each RTO. Particularly, it does not appear FERC discussed
the New York ISO's study showing that weekly settlement would result in a net cost
to end users -- a study whose results were also omitted from the earlier FERC NOPR
in what Multiple Intervenors has assailed as a "surprising" decision.
FERC further mandated that RTOs reduce the extension of unsecured credit to no more
than $50 million per market participant. The Commission established, for each organized
wholesale electric market, a maximum level of $100 million of unsecured credit for
all entities within a corporate family.
"The Commission further disagrees that an aggregate cap is not needed in a corporate
family structure that has both unregulated entities and regulated utilities. Regulated
entities, even those with cost-of-service rates, do not necessarily have a revenue
stream guaranteed to cover wholesale market costs, and thus should not be assumed
to be without risk of default," FERC said.
FERC eliminated entirely unsecured credit for Financial Transmission Rights (FTR)
positions. "The Commission disagrees with commenters that assert that LSEs using
FTRs to hedge for congestion should be exempt from the prohibition on the use of
unsecured credit in the FTR market. Even an LSE with generation backing the FTR
may encounter changes in the system that outstrip (perhaps substantially outstrip)
the hedge," FERC said. The Commission will not allow the netting of credit requirements
among FTR and non-FTR positions, nor will it waive the requirements for so-called
"fixed price" transmission congestion contracts.
FERC granted RTOs minimal leeway with respect to mandating the central counterparty
model, under which the RTO would take title to all transactions in the market. While
the Commission favors adoption of the central counterparty model as a means to address
mutuality concerns, "the Commission is open to considering other solutions to this
The Commission directed each ISO and RTO to submit a compliance filing that includes
tariff revisions to include one of the following options:
Establish a central counterparty
Require market participants to provide a security interest in their transactions
in order to establish collateral requirements based on net exposure.
Propose another alternative, which provides the same degree of protection as the
two above-mentioned methods.
Choose none of the three above alternatives, and instead establish credit requirements
for market participants based on their gross obligations.
This compliance filing must be submitted by June 30, 2011, with the tariff revisions
to take effect October 1, 2011.
Several market participants, including competitive suppliers, had noted that the
central counterparty model would increase administrative costs, implicate state tax
and other issues, and will not provide the assurance of mutuality the Commission
believes it will, since the RTO will merely be acting as an “agent” of a buyer in
taking the title of electricity. Mutuality may not be established as the RTO will
not take on the debt obligation for market purchases, since the RTO will only be
obligated to pay market sellers to the extent of its collections from market buyers.
FERC will require RTOs to specify in their tariffs the conditions under which they
will request additional collateral due to a material adverse change. This list should
not be exhaustive and the tariff provisions should allow the ISOs and RTOs to use
their "discretion" to request additional collateral in response to unusual or unforeseen
circumstances, FERC said.
The Commission will require each RTO to adopt tariff language that limits the time
period granted to market participants to post additional collateral. In addition,
FERC will require each RTO to allow no more than two days to cure a collateral call.
Each RTO must develop tariff language specifying minimum participation criteria to
be eligible to participate in the organized wholesale electric market, such as requirements
related to adequate capitalization and risk management controls. The Commission
will not specify such criteria at this time, and instead directed each ISO and RTO
to develop these criteria through their stakeholder processes.