Energy Legal Blog

FERC Embraces Some Industry-Endorsed Business Standards, Rejects Others

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.

FERC Lessens Burden of Merger, Holding Company Rules

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.

FERC Cautiously Approves Entergy ICT Plan

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.

FERC Takes First Step of Many in PJM Capacity Market Makeover

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 Ups Renewable Energy Requirements

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.

Economic Escape Valve to Moderate Maryland's Tough Emissions Law

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." 

FERC Rebuffs Demands that It Reinstate “Legitimate Business Purpose” Rule

In an April 17 order, FERC characterizes its new anti-manipulation rule for wholesale sales and transmission of power as “a ‘catch-all’ provision reaching all manner of fraud perpetrated by any entity in connection with a transaction subject to the jurisdiction of the Commission.”   [See FERC Jettisons "Legitimate Business Purpose," Retains Other Rules for Natural Gas and Power Wholesalers]  The April 17 order rejected California and New England regulators’ and certain public power organizations’ challenges to FERC’s decision to rescind a provision in market-based tariffs and rate schedules — known as Market Behavior Rule 2 or MBR 2 — that had prohibited market-based wholesalers “from engaging in actions that are without a legitimate business purpose and that are intended to or foreseeably could manipulate” market prices, conditions or rules for electric power or transmission.  According to FERC, the catch-all anti-manipulation rule rendered MBR 2 (as well as a comparable proscription in natural gas company codes of conduct) unnecessary.

Contrary to claims that it could and should have retained MBR 2, FERC explained that Congress in the recently enacted Energy Policy Act of 2005 directed that a different approach be taken to preventing market manipulation.  Specifically, Congress directed FERC in EPAct 2005 to base its anti-manipulation rule on the anti-fraud provisions of the Securities Exchange Act of 1934, which prohibits “knowing or intentional conduct” that is designed to deceive or defraud.  MBR 2’s lower standard prohibiting behavior that “foreseeably could manipulate” market prices or rules, FERC explained, is inconsistent with Congress’ directive.  Moreover, FERC added that the new anti-manipulation rule achieves a desirable uniformity by prohibiting knowing or intentional deception or fraud by any entity — which includes power sellers and buyers, such as public power and coops, not directly regulated by FERC — whereas MBR 2 applied only to wholesalers operating under a FERC market-based tariff or rate schedule. 

Notably FERC also dispatched the contention of New England regulators and public power organizations that MBR 2 is still needed because, unlike the new anti-manipulation rule, MBR 2 prohibited the knowing exercise of market power.  Not so, instructed FERC.  Market power is a “structural  issue to be remedied, not by behavioral prohibitions, but by processes” that occur “in the screening process before [FERC] grants an application for market-based rate authority” and when FERC reviews changes in an applicant’s status or updated information in the applicant’s triennial report on market power.  Further, when market power is detected by theses processes, provide prospective remedies to eliminate or mitigate market power.  In contrast, remedies that reach back to undo market manipulation, including disgorgement of profits, are available under the new anti-manipulation rule.

ColumbiaGrid Supplants GridWest in Pacific Northwest

Following an April 11 meeting among its remaining stakeholders, GridWest, the much-maligned proposed transmission organization for the Pacific Northwest, voted to dissolve for lack of financial support.  Once the giant of the Pacific Northwest, Bonneville Power Administration (BPA), decided to pull out of GridWest last November, it was just a matter of time before the proposed organization faltered.  See Pacific Northwest Grid Restructuring Proposal Fails, Utilities Vow to Continue On Without Bonneville

In lieu of GridWest, six power operators have proposed to create a new organization, ColumbiaGrid, which will seek to improve reliability in the region without triggering federal regulation by FERC.  ColumbiaGrid will constitute itself as a non-profit corporation in Washington State.  Its participants will include BPA, Avista Corporation, the Chelan and Grant County Public Utilities Districts, Puget Sound Energy, and Seattle City Light.  Unlike GridWest, the ColumbiaGrid structure will not function as an RTO due to the strenuous opposition of BPA customers (primarily the PNW's public power agencies) to creation of any kind organization that would be subject to federal regulation. See Grid West Parties, BPA Go Separate Ways

Contract Rights Let Independent Generators Continue Fight for Reactive Power Payments

Last fall, FERC agreed with Entergy Services, Inc. that the utility need not pay non-affiliated generators for supplies of reactive power within their specified power factor range (the "deadband" range) so long as Entergy does not compensate its own or its affiliated generators for the same supplies.  FERC's orders appeared to cut off future payments for reactive power to all generators interconnected to the utility. 

Following FERC’s orders, however, generators argued that they should have the right to litigate whether their interconnection agreements with Entergy — which are separate from Entergy's general rates and practices — grant them an independent contractual right to be paid for reactive power service.  FERC agreed in three separate orders (ER05-1419, ER05-1358, ER05-1394) that the generators could exercise their rights under the contract, and authorized them to seek compensation from Entergy in separate FERC proceedings.  This turn of events illustrates the importance of specifying rights to payments in contracts rather than relying solely on a counterparty's tariff and rate schedule. 

Ohio Regulators Provide Ratepayer Funding for AEP Clean Coal Plant

The Public Utilities Commission of Ohio (PUCO) has granted AEP the authority to recover in rates construction costs up to $23.7 million related to its proposed integrated gasification clean coal (IGCC) plant.  Critics argued that the PUCO should not allow AEP to recover its costs through rates in a deregulated electric power market such as Ohio's.  In response, AEP countered that it needed the generation to serve as provider of last resort to consumers in its Ohio service territory; thus granting it the ability to recover the IGCC costs in rates was justified.  The PUCO agreed. 

AEP next will need to respond to PUCO inquiries about the plant's rate structure, the benefits to consumers, the amount of local coal, the production and sale of byproducts of the combustion process, and the extent to which AEP can take advantage of federal and state IGCC incentives.  AEP plans to submit the requested information in October 2006, but harbors concerns that another long round of evidentiary proceedings on these issues could cause it to miss the 2010 in-service deadline imposed by its provider of last resort obligations. 

FERC Reorganizes OMOI as Office of Enforcement

“Let It Be Me,” NERC Tells FERC

Within days of FERC clarifying final elements of its Electric Reliability Organization (ERO) rule, the North American Electric Reliability Organization (NERC) filed with the agency its long-awaited ERO application.  On February 3, FERC issued its final rule establishing the criteria it will use to select an ERO, as mandated in the Energy Policy Act of 2005.  FERC Rule Allows Regional Entities to Propose and Enforce Reliability Standards]  But the rule didn’t go into effect pending a FERC decision on how to handle conflicts between the ERO's reliability standards and FERC-approved tariffs.  The revised rule provides that if FERC finds a conflict to exist, it may offer an RTO or affected utility an opportunity to submit a revised tariff, or FERC itself may modify the tariff itself under its Federal Power Act authority. 

On April 4, NERC submitted to FERC its application for recognition as the US ERO, along with over 100 proposed reliability standards that it would enforce under its new designation.  [NERC ERO Application]  Simultaneously, NERC submitted applications to Canada's National Energy Board and various Canadian provinces to be recognized as the reliability coordinator in Canada.  Little doubt exists that NERC will be certified as the US ERO since it has served in essentially that capacity since the 1960s.  But robust debate is expected as to whom the ERO’s reliability standards will apply, as some EPAct provisions exempt entities that engage solely in power distribution.  In addition, the extent of the ERO’s authority, if any, to delegate to regional councils standard-setting powers is likely to be contentious, with regional entities vying for region-specific standards and FERC wanting to maintain uniform national standards.   

Ontario to Guarantee Minimum Price for Small Renewable Energy Sales

To boost renewable energy production by small developers, the Ontario Minister of Energy plans to set standard prices for the Ontario Power Authority's purchases of renewable energy from smaller generators.  According to the plan, the provincially-owned Power Authority would purchase the electric generation of eligible wind, biomass or small hydropower generators at a base price of Canadian $0.11/kWh.  A higher price, Canadian $ 0.42/kWh, would apply to electricity from solar power.  The program is expected to be implemented in the fall of 2006.

Promoting power generation from renewable and clean sources in an efficient fashion has proven a vexatious issue for governments in many countries.  North American and European governments have resorted to tax incentives, various kinds of subsidies, renewable portfolio standards (requiring utilities to procure a certain amount of renewable energy), feed-in tariffs (requiring utilities to pay producers set rates for renewable energy), voluntary retail green power programs, and end-use purchases by government entities.  In the U.S. in recent years, the federal Production Tax Credit and state renewable portfolio standards have been the engines driving renewable development.  But while these programs lower costs and create sales opportunities, they do not guarantee minimum prices as Ontario now proposes.

Ontario has already established a goal of obtaining 10% of its electricity from renewable energy by 2010.  The standard offer program would facilitate production by smaller developers by obviating any need to secure contracts with individual utilities and by guaranteeing the price in sales to the Power Authority.  The latter feature renders the Ontario program similar to the feed-in tariffs that have driven wind energy development in Germany and Spain and made those countries among the world leaders in wind energy development.  

Constellation-FPL Merger Snags in Maryland

With the repeal of PUHCA, (see Congress Enacts Energy Bill and FERC Pares Back Accounting & Record Keeping, but Retains Strict Transfer Pricing for Public Utility Holding Companies under PUHCA 2005) many in the industry expected to see an explosion of merger activity.  The bloom may be wearing off that rose a bit, at least in the state of Maryland.  With the prospect of significant retail rate increases looming, Maryland's legislature has sought to strike back by holding up the proposed merger between Constellation Energy Group and FPL Group, Inc.  Last week, Maryland lawmakers passed two separate bills that would halt the merger unless Constellation softens the impact of an expected 72% retail rate increase to customers of its local subsidiary, Baltimore Gas & Electric, scheduled to take effect this summer.  While the rate increase is apparently unrelated to the merger, and comes as a result of increased fuel costs and the expiration of retail price caps that have been in place since electric deregulation in Maryland, the legislature has seized on the Constellation-FPL merger as a potential means to avoid the politically unpopular rate jump. 

One bill, HB 1713, would give the legislature the right to veto the merger.  Another bill,  SB 1099, would undo major sections of electricity deregulation in the state, and would prohibit the merger unless Constellation returns to its customers $528 million in stranded cost recovery it received under deregulation.  Another recently passed bill, SB 1102, would remove from office the current members of the Maryland Public Service Commission, each of whom was appointed by the governor.  Proponents of removing the current commissioners contend that they are too closely aligned with the electric industry and have failed to adequately protect consumers.  All three bills are now being considered by Governor Robert Ehrlich (R).  While it appears Gov. Ehrlich may veto the bills, the Democratic-controlled Maryland General Assembly may have the votes necessary to override a veto.  The General Assembly adjourns April 10.   

Constellation executives have been meeting with the governor and legislative leaders in an attempt to design a rate plan that lessens the retail rate impact.  Under the current proposal, BG&E would borrow $750 million and phase in the rate increase over the next year, instead of implementing it all at once.  Whether it can come up with a plan that can satisfy public officials in time to save the merger remains to be seen.