Energy Legal Blog

Pursuant to a December 2002 memorandum of understanding, the North American Electric Reliability Council (NERC) and the North American Energy Standards Board (NAESB) set standards for the operation of wholesale electric power markets, with NERC taking the lead on engineering and reliability standards and NAESB on commercial business standards, both of which are intended to complement each other.  In an April 25 Order No. 676, FERC approved some and rejected other new business standards that NAESB’s non-profit Wholesale Electric Quadrant (WEC) developed for public utilities.  The approved standards go into effect July 1, 2006.

Approved Standard WEQ-007 prescribes how inadvertent energy imbalances can be repaid.  It codifies the existing practice of allowing control area operators — called Balancing Authorities — to pay back in kind or in cash.  To the consternation of typically smaller utilities that rely on others for control-area services, non-control areas remain subject to a $100 per MWh imbalance charge and do not have the option of settling their imbalances in kind.  Whether to end this apparent discrimination FERC committed to resolve in a future rulemaking.  WEQ-007 is also problematic because it perpetuates the incentive to run negative imbalances during periods of high or peak demand when wholesale prices are high and then repay in kind during periods of low demand when prices are lower.  FERC dodged this issue by repeating that WEQ-007 deals only with “inadvertent” imbalances, whereas any pattern of leaning on one’s neighbors during periods of high demand would be “advertent” and subject to punishment, if detected.

For transmission customers, it is significant that FERC rejected proposed Standard 001-9.7 providing that long-term transmission that is redirected on a firm basis — i.e., the original receipt and/or delivery points are changed —  does not confer on the transmission customer renewal or “rollover” rights to the redirected path, unless otherwise mutually agreed.  FERC rejected this proposed standard because it contradicts the open-access transmission tariff, section 22.2.  That section gives a long-term firm transmission customer rollover rights to the original path until such time as that path is redirected on a firm basis, and then to any redirected firm path that has been granted and remains in effect at the end of the transmission service agreement.  These rollover rights can be defeated only by the transmission operator showing that the capacity at issue is needed to provide service to native retail load or is otherwise already contacted.

In the same order FERC ruled that it was powerless to prevent NAESB from charging a fee for access to its copyrighted standards.  So long as the standards are reasonably available, FERC can adopt them by reference (as it did in this order) and require compliance by all power industry participants subject to FERC’s jurisdiction.

In two April 24 orders, FERC attempts to coordinate its overlapping merger and utility holding company rules.  FERC also aims to strengthen its protection of customers from risks perceived to arise from repeal of the Public Utility Holding Company Act of 1935 (1935 Act).  Driving these rules, FERC explains, is the agency's desire to stimulate investment in the electricity sector and accommodate public utilities' day-to-day financial operations. 

In Order No. 667-A, FERC tweaked its December 2005 Order No. 667, which implemented the Public Utility Holding Company Act of 2005 (“PUHCA 2005″) primarily a recordkeeping statute that replaced the 1935 Act.  As originally proposed, these recordkeeping requirements were criticized as an unreasonable burden.  The April 24 order amplifies exemptions to the recordkeeping requirements.  For example, holding companies that own only QFs, EWGs, or FUCOs, while meeting the definition of a “holding company,” would nevertheless be exempt from the recordkeeping requirements.  FERC also affirmed an exemption for holding companies that operate primarily within a single state, and explained that a company would qualify for this exemption if no more than 13% of its revenues from public utility operations were derived from outside that state.

FERC took the opportunity in Order No. 669-A to simplify its merger rules under Federal Power Act § 203.  FERC extended to domestic mergers the four-part test, which heretofore had applied only to foreign acquisitions.  A utility will now be required to verify that a transaction does not result in:  (1) transfer of facilities between traditional public utility associate companies with captive customers and associate companies; (2) new issuances of securities by traditional public utility associate companies with captive customers for the benefit of associate companies; (3) new pledges or encumbrances of assets of traditional public utility associate companies with captive customers in favor of associate companies; and (4) new affiliate contracts between non-utility associate companies and traditional public utility associate companies with captive customers.  If merger applicants cannot make these showings, then they may withdraw from the merger or undertake a more detailed demonstration that the transaction nonetheless would be consistent with the public interest.  FERC also clarified that companies owning only QFs, EWGs, or FUCOs are authorized to acquire securities of additional QFs, EWGs, or FUCOs.  Order No. 669-A also grants banks and financial institutions blanket authorization for the acquisition of securities  in connection with their fiduciary, underwriting, and hedging activities.  In addition, FERC expressed support for public utilities' participation in holding company intra-system cash management systems, and simplified its regulations to ensure that public utilities possess blanket authorization to acquire securities in connection with such money pools.

Making quiet retreat from its long insistence that transmission owners relinquish operational control of their systems to independent regional transmission organizations or RTOs, FERC acquiesced in Entergy's much less independent Independent Coordinator of Transmission (“ICT”) concept, which the southern utility holding company first proposed nearly one year ago.  [Duke Energy Asks FERC to Approve MISO as ICT for Duke Facilities; Entergy and SPP Come to Terms on ICT Agreement; [ER05-1065].   

Under the plan, the Southwest Power Pool (“SPP”) will act as the ICT for Entergy's transmission system.  In that role, SPP will grant or deny requests for transmission service, calculate available flowgate capability, and administer Entergy's OASIS.  In a notable break with past practice, the plan allows Entergy to demand that interconnecting customers pay to upgrade Entergy's transmission grid (“participant funding”).  Until now, only RTOs were given this option and were required to reserve to funding participants the transmission capacity created or expanded as a result of the participants' investment.   

As part of the ICT, FERC also authorized Entergy to price transmission service in a way that purports to protect customers from congestion costs.  As approved, the ICT will oversee a Weekly Procurement Process that is intended to allow merchant generators to compete with Entergy plants to serve load within Entergy's service territory.  These two latter elements have sparked some criticism, as independent power producers argue that Entergy's pricing proposal would not, in some cases, pay them for past upgrades to the grid, and that the weekly procurement process would not allow for capacity payments. 

While FERC approved the ICT plan over these objections, the agency pointedly characterized the ICT as an “experiment” and established numerous metrics by which to monitor the ICT's progress.  Entergy must submit periodic reports to FERC on the ICT's operations, as well as a comprehensive report once the ICT has been in place for a year.  In addition, Entergy must provide annual updates to state regulators that document any savings customers receive from the ICT.  FERC granted authorization for a four-year period, after which Entergy will need to file for extension should it wish to continue with the ICT.  Other utilities, in particular Duke Energy and MidAmerican Energy, who have filed similar plans with FERC in recent months, will be paying close attention to the fate of Entergy's ICT to see whether it wins FERC's full confidence and survives its full four-year term.

More than eight months after PJM proposed to replace its existing installed capacity (ICAP) requirement with a Reliability Pricing Model (RPM), FERC agreed with the RTO that the current model is an unjust and unreasonable, and fails to induce needed generation investment.  But did it also embrace RPM?  Not likely.  Instead the agency decided to mull over RPM for yet more months together with more public comment and conferences, with no end in sight. 

PJM’s existing ICAP market does not distinguish between the value of generators located in constrained areas and elsewhere, and does not require forward procurement of capacity.  FERC agreed with PJM that its ICAP rules do not support continued entry of new generation, because a generator could not expect to recover its costs through capacity and energy market revenues.  While FERC endorsed numerous features of RPM, it stated it could not at this time determine that RPM was a just and reasonable substitute for the current rules.  Instead, FERC drew up the next procedural steps, including a paper hearing and a technical conference. 

The paper hearing will address how to:  

• delineate locational capacity markets that capture the operational characteristics of the PJM system,
• determine the duration of capacity commitments, which FERC agreed should be committed four years in advance,  
• integrate generation, demand response, and transmission solutions,
• design the downward-sloping demand curve used in the capacity auction, as well as details regarding the alternative method FERC approved, setting fixed capacity requirements for load servers, and
• coordinate the capacity and energy markets.

PJM is to provide its views on these questions by May 19, 2006.  Public comments responding to PJM are due June 2, with reply comments scheduled for June 16.  The issues to be addressed at the technical conference include the shape of the demand curve and the alternative long-term fixed resource requirement option. 

Several other organized markets have grappled with how to induce sufficient generating capacity.  The New York ISO was the first to price capacity locationally on a downward-sloping demand curve.  ISO-NE’s comparable proposal provoked a backlash from representatives of capacity deficient areas, primarily in Connecticut, and were ultimately diluted into a pending forward capacity market proposal.  In the west,  CAISO is struggling with these same issues as part of its Market Redesign and Technology Upgrade.  Meanwhile, Midwest ISO so far has stuck with the simplest solution ― no capacity market at all.

New Jersey’s Board of Public Utilities (BPU) has quintupled the Renewable Portfolio Standard (RPS) for the state's utilities from 4% to 20% by 2020.  This move puts New Jersey at the forefront of renewable energy development. 

Another emerging feature in RPS is to set aside a certain portion of the RPS for specific resources.  This fosters development of a wider range of resources, some of which might otherwise be uneconomical.  In particular, set-asides for solar power – which is among the most expensive form of renewable energy – are becoming more popular.  The BPU’s new regulations include a 2% solar set-aside, which is forecast to require 1500 MW of solar power installations.

The BPU’s decision follows a challenge by newly-elected governor Jon Corzine to create a new energy policy, as well as extensive studies on the feasibility and benefits of adopting a 20% RPS.  In support of its decision, the BPU cited a raft of benefits expected from renewable energy, including fuel diversity, price stability, clean air and reduced greenhouse gas emission that cause global warming.

The Healthy Air Act  that Maryland Governor Ehrlich signed into law in early April requires seven Maryland power plants to reduce their emissions of sulfur dioxide by 90% by 2015; nitrogen oxides by 80% by 2015; and mercury by 80 % by 2010 and by 90% by 2012.  The law also requires Maryland to join the Regional Greenhouse Gas Initiative, a compact of seven northeastern and middle Atlantic states that have pledged to cut 10 % of  their carbon dioxide emissions by 2018. 

While these requirements represent one of the toughest emissions laws to be enacted to date in the United States, the law also contains an escape valve:  Maryland's Department of the Environment is authorized to reduce or waive penalties for plants that fail to reach the targets based on a determination that the cost of pollution controls required to comply with the law would “significantly increase electric rates.” 

With the new law, Maryland joins Massachusetts, New Hampshire, and North Carolina as the only states to enact laws requiring comparable reductions of multiple pollutants.  The law's passage, however, comes at the same time as Maryland consumers and utilities struggle with the implementation of industry deregulation and the attendant power price increases – a juxtaposition that, together with the new law's economic waiver provision, may decrease the effectiveness of the Health Air Act in curbing emissions.