Energy Choice        
                            

Matters

Advertise with Energy Choice Matters

This space is taken, but prime spots still available on each sidebar.  Call Paul Ring 954-205-1738

FERC "Reforms" RTO Credit Rules, Increases Costs to End Users

Email This Story
October 22, 2010

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 (RM10-13).

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 weekly settlement.

"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 concern."

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.

   
Email This Story
 

HOME

Copyright 2010 Energy Choice Matters.  If you wish to share this story, please email or post the website link; unauthorized copying, retransmission, or republication prohibited.

 

Be Seen By Energy Professionals in Retail and Wholesale Marketing

Run Ads with Energy Choice Matters

Call Paul Ring

954-205-1738