Energy Legal Blog

Generation-Friendly Transmission Companies to Reimburse for Network Upgrades

Independent electric transmission owners International Transmission Company (ITC) and Michigan Electric Transmission Company (METC), effective July 11, 2007, will reimburse qualifying interconnecting customers ― primarily new power generating units ―  100 % of the cost of transmission system upgrades for which interconnecting customers advance payment.  In a September 7 order the Federal Energy Regulatory Commission (FERC) approved amendments to the Midwest ISO tariff authorizing the two independent transmission companies to make these complete reimbursements to interconnecting customers who are qualified by reason of contractually committing to provide service for at least one year to Midwest ISO network customers or obtaining network resource designation at the time commercial operation begins.  Notably, the only opposition came from the former owners of ITC and METC, Detroit Edison and Consumers Energy, respectively, and the Michigan Public Power Agency.

The approach of ITC and METC was once FERC's standard practice; while the interconnecting customer could be required to advance full funding for the upgrades to the network needed to interconnect its new generator or transmission line, the customer would be reimbursed over time from transmission revenues. That was because system upgrades generally benefit everyone connected to the grid and those beneficiaries should all contribute to upgrades in proportion to their use of the gird.  Only when evidence to the contrary was introduced would there be less than complete reimbursement.

Under pressure from vertically integrated transmission owners, FERC strayed from this approach to cost allocation, grounded in the realities of a synchronously interconnected electric transmission system.  The approach of these truly independent transmission companies is refreshing.

Rising Capacity Costs Prompt Duquesne Light to Divorce PJM

Duqesne Light Company wants to sever ties with the PJM Interconnection regional transmission organization (RTO).  Duquesne cites the increased capacity costs resulting from PJM’s implementation of the new reliability pricing model (RPM) for capacity sales, and is asking FERC to allow it to withdraw before PJM’s next capacity auction that will cover 2009 deliveries.  PJM responded that it is too late to exclude Duquesne from that auction, and that numerous questions must be resolved, including how Duquesne would resolve it reliability requirements.  A number of others have likewise objected to Duquesne’s precipitous withdrawal. 

Duquesne has stated it intends to join the Midwest ISO, which it already borders from its location in Western Pennsylvania.  Of course, PJM is not the only organized market where member dissatisfaction has led to withdrawal.  Stating that a cost-benefit analysis compelled the conclusion, Louisville Gas & Electric and Kentucky Utilities left the Midwest ISO in 2006.  And due to unhappiness with capacity markets that mirror Duquesne’s complaint against PJM, the State of Maine has threatened to withdraw from NEPOOL and thereby ISO-New England. 

While utility membership in organized markets is voluntary, it is clear that withdrawals raise vexing issues of allocating costs to a shrunken customer base as well as long-term planning.  With the complex RPM market finally in operation, market participants are already being forced to examine a new twist, the impact of a utility’s withdrawal on capacity procurement and reliability.

FERC Finds PJM Not in Violation of Tariff in Months-Long Dispute with Customers over Independence of Market Monitor

In response to PJM Interconnection, Inc.'s (PJM) Offer of Settlement to resolve its much-publicized  dispute regarding the independence of PJM's Market Monitoring Unit (MMU) and allegations of tariff violations, interested parties on August 22 gave the Federal Energy Regulatory Commission (FERC)  a wide range of options to pursue in response to the Offer of Settlement, including: (1) setting the dispute for evidentiary hearing; (2) invoking settlement judge procedures; or (3) postponing action on the matter pending the agency’s action on the Advanced Notice of Proposed Rulemaking's goal to develop industry standards for the MMU structure. 

On September 20 FERC concluded that there was no evidence that PJM violated its tariff; thus no hearing was necessary.  Nevertheless, FERC ruled that the evidence was more than sufficient to demonstrate that the PJM MMU reporting requirements are unjust and unreasonable.  While the MMU before was under an "unusual degree of supervision" by PJM management, FERC directed in its order that, whatever other conclusion the parties may reach during settlement proceedings, the resolution must include provisions that the MMU report solely to the PJM Board or an independent committee of the Board.   Commissioner Suedeen Kelly noted in her statements that more specific tariff provisions are needed to promote a stronger working relationship between the MMU and its overseer and to engender confidence in market operations.

In its September 20 Order and Commission open meeting, FERC acknowledged and commended the complainants and Dr. Joseph Bowring for bringing this important matter to the Commission's attention, commended PJM Board's prompt and positive actions in promoting settlement discussions with its Offer of Settlement, and expressed its opinion that "a consensual resolution is most likely to restore confidence in the efficient, impartial and competitive operation of PJM's markets and in the monitoring of those markets."  Commissioner Jon Wellinghoff added that the pending rulemaking will help define the role of an MMU, but cautioned that it is PJM itself, in the settlement procedures with customers, that can best restore confidence in the markets PJM administers.  If not, then the agency made clear it is ready to step in and resolve structural and functional issues surrounding the PJM MMU.

Commodity Futures Trading Commission Echoes Arguments of Alleged Manipulators of the Gas Futures Market

Southeastern Group Undertakes Regional Transmission Planning

A group of utilities in the southeast ― where utilities have to date resisted forming regional transmission organizations ― have announced a proposal to develop an interregional transmission planning process.  Under the plan to be released September 14, the utilities will work jointly to collect data, coordinate planning assumptions, and address stakeholder study requests.  The coordinated efforts will provide a centralized information source for transmission users, who will no longer have to consult each transmission owner separately.  The effort answers FERC's Order No. 890, which mandated broader regional coordination of transmission planning. 

Involved in the efforts are several major utilities, including Duke Energy Carolinas, Entergy, Progress Energy Carolinas, South Carolina Electric & Gas, Southern Company, and the Tennessee Valley Authority, as well as a number of municipal transmission providers and electric coops.  The effort will build upon a few small regional planning groups that already exist in areas of the southeast, such as the North Carolina Transmission Planning Cooperative, but will allow broader information sharing and cooperation across the entire region.

New York Commission Pushes Utilities to Decouple Revenue from Sales

The New York Public Service Commission (NYPSC) has ordered New York State Electric & Gas to develop plans for "decoupling" revenue from sales volume for both its electricity and gas service.  This is the State’s latest push to promote energy conservation, efficiency and diversification, but requires regulators to tackle the thorny issue that arise when utilities lose money if sales fall.

Increasing energy efficiency holds great promise for reducing the nation’s energy demand.  Efficient energy use may reduce energy production, lessens greenhouse gas emissions, and save fuel and infrastructure costs.  Utilities, however, typically profit in proportion to the volume of their sales. Consequently, efficiency that reduces consumption is not in a utility's financial interest.  Indeed, few industries, if any, tout a reduction in sales as a viable business model.

North Carolina Brings Southeast to RPS Table; Illinois & Delaware Expand RPS Laws

Various states around the country have recently created or expanded their renewable portfolio standard (RPS) requirements.  The combination of traditional RPS requirements with complimentary initiatives, including cost recovery incentives, energy efficiency directives and voluntary green power programs, characterize these recent additions to the nation's RPS goals.

With its recent enactment of a Renewable Energy and Energy Efficiency Portfolio Standard (REPS), North Carolina has become the first southeastern state to join the ranks of RPS states.  The REPS will be phased in beginning in 2012; it requires that by 2021 all investor-owned utilities within the state meet 12.5% of their 2020 energy needs from renewable energy resources or energy efficiency measures.  A reduced requirement of 10% applies to rural electric cooperatives and municipal electric suppliers.  Until 2018, up to 25% of the requirement may be met through energy efficiency efforts, including combined heat-and-power systems powered by non-renewable fuels.  After 2018, 40% of the standard may be met by energy efficiency strategies.  Other noteworthy facets of the new law are its provisions (1) permitting utilities to recover certain incremental costs incurred to comply with the REPS, to fund renewable energy or energy efficiency research, or comply with any future federal RPS mandate, (2) requiring electric power suppliers to implement demand-side management and energy efficiency measures and providing for cover recovery for those measures, and (3) extending rate recovery to construct costs associated with out-of-state generating facilities.   

Building on its previous voluntary renewable portfolio goal of 8% by 2013, Illinois recently enacted a new law that creates the Illinois Power Agency (IPA) and charges it with developing electricity procurement plans for state utilities serving over 100,000 customers and then competitively procuring energy according to those plans.  The IPA's procurement activities must also meet an expanded and now-mandatory RPS of 25% by 2025, beginning in 2008 with a 2% requirement.  A minimum of 75% of the renewable energy must be produced from wind.  The new law also requires that utilities establish annual energy savings goals in order to meet a percentage of their energy delivery requirements through efficiency efforts. 

CPUC to Consider Innovative Energy Efficiency Incentives for State's IOUs

The California Public Utilities Commission (CPUC) will soon consider an innovative incentive program to encourage the state's investor-owned utilities (IOU) to meet energy savings goals.  Based on an August 9 proposed decision by CPUC Commissioner Dian Gruenich and Administrative Law Judge Meg Gottstein, the proposal would pay the IOUs -- include Pacific Gas & Electric Co., San Diego Gas & Electric Co., Southern California Edison Co., and Southern California Gas Co. -- up to $323 million over three years if they exceed the base targets.  If utilities satisfy these goals, the plan would purportedly save California ratepayers $2.4 billion and cut about 3.4 million tons of carbon dioxide emissions in 2008.  Conversely, if the utilities fail to meet the base targets, the plan would impose monetary penalties on them.  The proposal caps both potential earnings and losses for shareholders at $500 million.

Commissioner Gruenich, the plan's chief proponent, argued that the proposal would provide "both a meaningful level of shareholder earnings and an estimated return of over 100 percent on ratepayers' investments in energy efficiency as the utilities reach toward and exceed our 2006-2008 energy savings goals."  The proposed decision is on the CPUC's agenda for its September 20 meeting.