The Federal Energy Regulatory Commission (the Commission) issued an order on Thursday, March 19, 2015, refusing to allow the abandonment of certificated working gas capacity when the reason for the request was unrelated to the physical characteristics of the storage facility and unsupported by engineering or geological data.  The applicant had sought the abandonment authorization for the sole purpose of reducing its lease payments, which are largely based on the certificated working gas capacity of the facility.

The order, Tres Palacios Gas Storage LLC, 150 FERC ¶ 61,197 (2015), was issued following an  application by Tres Palacios Gas Storage LLC (Tres Palacios) for authorization to abandon a significant amount of its certificated working gas storage capacity in a salt dome storage facility in Matagorda and Wharton Counties, Texas.  Tres Palacios claimed that abandonment was justified because market conditions were such that it could not sell the capacity at rates that it considered acceptable.

In denying the application, the Commission ruled that Tres Palacios’s request was inconsistent with Commission policy, which requires specific facility parameters for each cavern, such as cushion gas capacity, working gas capacity and minimum pressures, and was inconsistent with Tres Palacios’s certificate authority, which authorizes specific parameters for each cavern.  In addition, the Commission explained that no geological or engineering data was submitted to support the change.  The order reaffirmed that certificated capacity is based on the physical attributes of a facility and that certificated working gas capacity is “unrelated to the amount of working gas capacity the storage company is able to sell.”

Karol Lyn Newman and Jessica Bayles represented the lessor, Underground Services Markham, LLC, in the proceeding before the Commission.

Commissioner Philip Moeller of the Federal Energy Regulatory Commission (FERC) held a public meeting on September 18, 2014 to discuss ideas to facilitate and improve the way in which natural gas is traded and to explore the concept of establishing a centralized natural gas trading platform.  Although not an official FERC conference, the ideas at issue were an extension of FERC’s recent focus on gas-electric coordination.  During the well-attended meeting, Commissioner Moeller presided over a large roundtable discussion of stakeholders, including electric generation owners, natural gas producers, pipelines and marketers, who engaged in a spirited discussion of whether natural gas supplies are meeting the needs of electric generators and improvement in supply practices.  The central focus of the meeting was the creation of a natural gas information and trading platform containing bids and offers for the purchase and sale of commodity and capacity for receipt and delivery on points across multiple pipeline systems.

Participants agreed that the natural gas industry is evolving and an increasing share of natural gas is being supplied to electric generators—customers with different needs than the local distribution companies the natural gas pipeline industry was traditionally designed to serve.  Most participants further agreed that the needs of generators do not always align with pipelines’ traditional services.

Natural gas-fired generation owners voiced concerns regarding unknown or unreasonable commercial terms in pipeline service agreements, a lack of transparency surrounding available services and illiquidity in the natural gas market.  Pipeline representatives highlighted the availability of new services such as extra nomination cycles, no-notice service and the ability to reverse flow as examples of services intended to accommodate generators.  Nevertheless, the pipeline representatives also made the point that natural gas liquidity is outside pipelines’ control as they do not have title to the gas they transport.  Marketers and organized exchange representatives added that they have been responding to generators’ needs by making available bespoke products and exploring new standardized products to match generators’ demands.

In addressing possible solutions to transparency and liquidity problems, most meeting participants urged incremental change and expressed a preference for industry solutions over FERC’s regulatory intervention.  Electric generators preferred increased use of non-ratable service, no-notice service and new, shaped products.  Other proposals included eliminating the shipper-must-have-title rule, facilitating competition between capacity release and pipeline overrun services and encouraging generators to purchase firm transportation service rather than interruptible service.

FERC has established a docket number to allow interested parties to file written comments on any issue that was discussed at the meeting.  Comments are limited to five pages and are due by October 1, 2014.

A New York town’s challenge to the Federal Energy Regulatory Commission’s (FERC) siting authorization for a natural gas pipeline compressor station was rejected by the U.S. Court of Appeals for the D.C. Circuit in Minisink Residents for Environmental Protection and Safety v. FERC.  The court’s August 15 decision denying the petition for review of residents of the Town of Minisink, when read in conjunction with its decision earlier this year in Delaware Riverkeeper Network v. FERC, delineates the scope of environmental impact analysis that the court will require of FERC  under the National Environmental Policy Act (NEPA).

Residents of the Town protested the compressor station’s location and urged FERC and Millennium to pursue an alternative site referred to as the Wagoner Alternative.  The Wagoner Alternative would have resulted in the compressor station being located in a less populous area but would have required the replacement of a seven mile pipeline segment (called the Neversink segment).  In developing its environmental assessment, FERC had actively considered the Wagoner Alternative but concluded that because of the need to replace the Neversink segment, the environmental impact associated with the Minisink location would be less and the Minisink location was therefore preferable.  FERC’s decision approving the Minisink proposal was split 3-2, with former Chairman Wellinghoff and current Chairman LaFleur dissenting, both Commissioners concluding that the Wagoner Alternative was the better option.

Fundamental to the D.C. Circuit’s decision was its finding that FERC had adequately analyzed the Wagoner Alternative and that there was ample evidence to support its determination that the Wagoner Alterative would have a greater impact due to the need upgrade the Neversink segment.  The petitioners attempted to undermine this finding by pointing to a Millennium PowerPoint presentation that they alleged showed that even if the compressor station were to be located in Minisink, Millennium still planned to replace the Neversink segment.  The court, however, did not consider the PowerPoint persuasive in light of both Millennium’s representation to FERC and Millennium’s counsel’s representation at oral argument that Millennium had no current plans to replace the Neversink segment.

In an instructive footnote, the D.C. Circuit contrasted this case to its recent decision in Delaware Riverkeeper, where it held that FERC improperly segmented and failed to consider the cumulative impact of four connected pipeline construction projects.  The court clarified that the “critical” factor in Delaware Riverkeeper was that all of the pipeline’s projects were either under construction or pending before FERC for environmental review at the same time.  The court acknowledged that the issue before them in Minisink Residents would potentially be “more troublesome” if Millennium were now planning to pursue the Neversink upgrade.

The Federal Energy Regulatory Commission’s (FERC) Order No. 1000 mandate that going forward the high-voltage electric transmission grid be planned and fairly financed regionally by all of its operators and beneficiaries, survived myriad challenges from 45 petitioners in the unanimous August 15 decision of a three-judge panel of the U.S. Court of Appeals for the D.C. Circuit in South Carolina Public Service Authority v. FERC.  The rigorous 97-page opinion rejected challenges coming from all directions to the 2011 rulemaking entitled “Transmission Planning and Cost Allocation by Transmission Owning and Operating Public Utilities.”

According to the panel, nearly all of the challenges misapprehended Order No. 1000’s regional planning mandate.  The court repeatedly emphasized that Order No. 1000’s mandate is nothing new, but rather the next step in evolving efforts under section 206 of the Federal Power Act to combat undue discrimination.  That evolution, the panel explained, began in 1996 when Orders No. 888 and No. 889 required that electricity transmission be “unbundled” from sales and offered via the internet pursuant to open-access tariffs, and 11 years later continued in Order No. 890’s directive that a transmission provider standardize how it measures available transmission capacity and open to its customers the process for planning transmission upgrades and expansions.

The panel’s decision affirmed FERC’s authority to require each of the key elements that FERC prescribed for regional transmission planning.  Those elements include:

  • All public utility transmission providers are required to participate in a regional planning process, and non-public utilities such as cooperative or municipal utilities effectively must also participate pursuant to a reciprocity requirement carried forward from Order No. 888.
  • The planning process must include procedures for taking into account federal, state and local laws and regulations affecting transmission, such as federal air quality rules and state or local renewable portfolio standards.
  • Transmission tariffs must be amended to remove provisions that confer on the incumbent transmission provider a right of first refusal to construct, own, and operate new regional transmission, thereby opening the regional process to input, innovation, and investment from non-incumbents and new entrants, subject to state and local restrictions on siting and eminent domain.
  • A methodology must be added to transmission tariffs for allocating up-front the cost of new regional transmission facilities, consistent with six principles, including a causation principle directing that the allocation be roughly commensurate with the benefits received by those consumers required to pay, and a prohibition on one region allocating costs to its neighbors without their advance consent.

FERC Chairman Cheryl LaFleur promptly praised the panel’s decision upholding Order No. 1000 in its entirety as critical for inducing the “substantial investment in transmission infrastructure [needed] to adapt to changes in its resource mix and environmental policies.”  In its decision the panel noted that the electric industry in 2008 estimated the infrastructure investment needed at $298 billion between 2010 and 2030.

Following FERC’s lead, the panel chose not rule at this time on challenges that elements of the regional planning mandate violate the Mobile-Sierra doctrine —eponymously named for two 1956 Supreme Court decisions —which limits FERC’s authority unilaterally to alter the terms of bilateral contractual relationships.  FERC explained that it would not rule on these challenges in the context of Order No. 1000, but would instead address them in connection with a transmission provider’s filing of tariff amendments in compliance with the Order.  Mobile-Sierra challenges prosecuted at that time are unlikely to succeed since precedents interpreting the doctrine give the Commission much greater leeway when implementing industry-wide changes to tariffs than when seeking to alter individual contracts.

The D.C. Circuit Court of Appeals recently issued an opinion holding that the Federal Energy Regulatory Commission (FERC) violated the National Environmental Policy Act (NEPA) when it segmented its evaluation of the environmental impact of four separately proposed but connected projects to upgrade the “300 Line” on the Eastern Leg of Tennessee Gas Pipeline Company’s natural gas pipeline system.  Going forward, the court’s ruling will likely compel proponents of interrelated or complimentary pipeline projects to seek their certification on a consolidated basis and will require FERC to evaluate their cumulative impact.

Tennessee Gas’s challenged Northeast Project was the third of four proposed upgrade projects to expand capacity on the existing Eastern Leg of the 300 Line.  The Northeast Project added only 40 miles of pipeline, while the four proposed projects combined to add approximately 200 miles of looped pipeline.  FERC approved Tennessee Gas’s first proposed upgrade, the “300 Line Project,” in May 2010.  While that project was under construction, Tennessee Gas proposed three additional projects to fill gaps left by the 300 Line Project, one of which was the Northeast Project.   As part of its review of the Northeast Project, FERC issued an Environmental Assessment (EA) required by NEPA that recommended a Finding of No Significant Impact.  The EA for the Northeast Project, however, addressed only the Northeast Project’s environmental impact without reviewing the cumulative impact of all four projects.

The D.C. Circuit held that FERC was in error for failing to consider the cumulative impact.  Under NEPA, the D.C. Circuit explained, FERC must consider all connected and cumulative actions.  The D.C. Circuit found no “logical termini,” or rational endpoints to divide the four projects and found the projects were not financially independent.  Rather, the court found the Northeast Project was “inextricably intertwined” with the other three improvement projects that, taken together, upgraded the entire Eastern Leg of the 300 Line.  The court held that FERC must analyze the cumulative impact of the four projects and remanded the case to FERC for consideration.

The Court emphasized that in this case, “FERC was plainly aware of the physical, functional, and financial links between the two projects.”  Regardless of whether an interstate pipeline initially plans to embark on a series of related upgrades, once FERC is aware of the interrelatedness of proposed expansion projects, it must take care to review any cumulative environmental impacts that may arise.

The D.C. Circuit’s decision may also be a warning that FERC must pay greater attention to the NEPA review in pipeline construction projects.  The D.C. Circuit also has before it this term a case alleging that FERC did not sufficiently consider the environmental review of the siting of a new pipeline compressor station in light of less environmentally intrusive alternatives.  See Minisink Residents for Environmental Preservation and Safety v. FERC, Case No. 12-1481.  Both cases take issue with the rigor of FERC’s environmental review under NEPA, and the D.C. Circuit’s decisions may signal a new era of increased focus on the environmental review process.

For more information, please contact your regular McDermott lawyer or:

Karol Lyn Newman: + 1 202 756 8405  knewman@mwe.com
Dan Watkiss: + 1 202 756 8144  dwatkiss@mwe.com

FERC’s Order No. 745 requiring independent regional grid operators  (RTOs and ISOs) in limited circumstances to compensate providers of state-authorized demand response services in the same amounts that they compensate electricity generators was vacated in a May 23, 2014 decision by the majority of a three-judge panel of the U.S. Court of Appeals for the D.C. Circuit in Electric Power Supply Association v. FERC.  Siding with challengers — principally electricity generators — Judge Brown writing for the two-judge majority held that FERC exceeded its Federal Power Act (FPA) jurisdiction over electricity wholesales and intruded impermissibly on retail jurisdiction reserved to states by “lur[ing]” retail customers into the wholesale markets of regional grid operators with “rich” incentives to reduce retail purchases and consumption whenever a net benefit accrues to the wholesale market in the form of lower market-clearing prices in the wholesale market.  Even if it had not vacated the rule based on this jurisdictional conclusion, the majority said it would have reversed the rule on an alternative ground urged by challengers.  According to those challengers, the rule also was arbitrary and capricious by requiring that demand response providers under limited circumstances be compensated at the same locational marginal price or LMP paid to electricity generators.

In a forceful dissent (running nearly twice as long as the majority opinion), Senior Circuit Judge Edwards disagreed with both the jurisdictional vacatur and the threatened reversal of the rule prescribing LMP payments in some circumstances on arbitrary and capricious grounds.  Demand response services at least arguably did not fall under the FPA reservation to states of all sales other than wholesales since demand response involves no sale at all, but rather a foregone sale or “negawatt.”  The court therefore, according to the dissent, should have deferred to FERC rather than presume greater expertise in interpreting the agency’s jurisdictional statute.   In addition, the dissent agreed with FERC that direct participation of demand response resources in wholesale markets entrusted to FERC improves the functioning of those markets in three ways:  (1) by reducing peak demand and system imbalances, it lowers clearing prices; (2) it mitigates the market power of generators (particularly pivotal suppliers); and (3) enhances system reliability by lowering demand in response to system emergencies. Incentivizing demand response that offers net benefits to wholesale markets through LMP payments is not unlike the capacity payments that the court found FERC could regulate in Connecticut Dept. of Public Utility Control v. FERC, even though ensuring adequate capacity in wholesale markets could incentivize, among other investments, investments in generation, which is regulated by the states.  Therefore, FERC was acting well within the parameters of its wholesale jurisdiction and the court’s precedents.

The disagreement between the majority and dissent on the LMP payments was even more pronounced.  Long the preferred method of pricing electricity in organized electricity markets, LMP is the marginal value of an increase in supply or a reduction in consumption at each notional location (node) within an organized RTO or ISO market at a given interval of time.  The majority (siding with FERC Commissioner Moeller, who dissented below from Order No. 745) objected to paying a demand response provider the same LMP as an electricity generator since the demand response provider does not incur the cost of generating or purchasing electricity, while a generator or other supplier does.  The dissent, in contrast, sided with the FERC majority in concluding that demand response providers incur other costs that generators and other suppliers do not incur and more importantly FERC, with judicial approval, ceased cost-based ratemaking in favor of market pricing (in the absence of market power) over a decade ago for all organized RTO and ISO markets.  Therefore, respective costs should not be a controlling consideration.

Because of the undisputed value of demand response in both wholesale and retail electricity markets and the sharp division on the court, FERC can be expected to petition for rehearing of the majority’s decision.

 

In three separate rehearing orders issued last Thursday, May 15, 2014, the Federal Energy Regulatory Commission reversed course on its decision in Order No. 1000 to prohibit references in transmission tariffs to state laws such as rights of first refusal (ROFR) to build transmission expansions.  The Commission determined on further consideration that excluding such state and local laws from transmission tariffs could lead to inefficiencies and delays in the regional transmission planning process because regions would have to spend time and resources evaluating potential transmission developers that would ultimately be prohibited by state or local law from developing a transmission project.  Commissioner Norris issued a statement opposing the Commission’s orders on the basis that they will exclude non-incumbents from participating in the regional transmission planning process, choking innovation and insulating incumbents from competition.

Order No. 1000 requires public utilities to participate in regional transmission planning and cost allocation planning for new transmission facilities.  In order to allow competitive bidding of projects and developers, Order No. 1000 requires public utility transmission providers to remove provisions in Commission-jurisdictional tariffs that establish a federal ROFR for an incumbent transmission provider with respect to building transmission facilities selected in a regional transmission plan.  Order No. 1000-A stated that it was not “intended to preempt or otherwise conflict with state authority over sitting, permitting, and construction of transmission facilities.”  However, the order also stated that it “would be an impermissible barrier to entry to require, as part of the qualification criteria, that a transmission developer demonstrate that it either has, or can obtain, state approvals necessary . . . to be eligible to propose a transmission facility.”

On rehearing of compliance orders for the PJM Interconnection, Midcontinent Independent System Operator and South Carolina Electric & Gas Company, the Commission held that while it will continue to require the elimination of federal ROFRs, regional operators and utilities could recognize exclusionary state and local laws and regulations as a threshold issue in the regional transmission planning process.  Specifically, the rehearing orders provided that tariffs could include state and local laws, giving incumbent utilities ROFRs and provisions excluding projects that alter the transmission providers’ use or control of rights-of-way.  The Commission reasoned that ignoring these state or local laws or regulations at the outset of the regional transmission planning process would be counterproductive and inefficient, and could delay needed transmission facilities.  In a dissenting statement, Commissioner Norris argued that this approach was irreconcilable with Order No. 1000 and condemns consumers to bear the burden of incumbents’ lack of innovation in developing transmission solutions and interest in preserving the status quo.

Primary regulators of energy transactions, the Federal Energy Regulatory and Commodity Futures Trading Commissions (FERC, CFTC or jointly Participating Agencies) began the new year by entering on January 2 two overdue Memoranda of Understanding (MOU), one on overlapping jurisdictions, the other on sharing of information generated in connection with market surveillance and investigations into suspected market manipulation, fraud or abuse.  Both MOUs became effective immediately.

FERC, with jurisdiction over physical natural gas and power transactions, and the CFTC, with jurisdiction over financially settled products such as energy futures and swaps, had battled in recent years over the reach of each other’s jurisdiction, culminating in a March 2013 decision of the U.S. Court of Appeals for the D.C. Circuit finding that FERC improperly invaded CFTC’s jurisdiction when, under authority of the Energy Policy Act of 2005, it sought to fine Amaranth Advisors trader Brian Hunter for allegedly manipulating  natural gas futures in order to increase the profitability of corresponding physical natural gas transactions.  When the Participating Agencies failed to meet the 2011 deadline of the Dodd-Frank Wall Street Reform Act for reaching the jurisdictional understanding, a troika of western-state senators with energy committee portfolios – Dianne Feinstein (D-CA), Ron Wyden (D-OR) and Lisa Murkowski (R-AK) – expressed concern and called on the two commissions to expedite action on an MOU.

The MOUs put in place procedures that replace a reactive status quo ante in which the two agencies collaborated and shared information, if at all, only upon the request of one or the other, with a proactive framework that obliges the staffs of both agencies to notify each other of requests from within their regulated community for authorizations or exemptions from authorization requirements that may implicate the other’s regulatory responsibilities.  Once so notified, the Notified Agency must promptly inform the Notifying Agency that it (1) has no interest, (2) has an interest, triggering a consultative process between the staffs of the Participating Agencies, or (3) wants to revisit the issue once a regulated company has filed request for an authorization or exemption or the Notifying Agency has instigated sua sponte an authorization or exemption.  If (2) is selected, then the triggered consultative process will seek to determine whether the CFTC has jurisdiction under the Commodity Exchange Act or FERC has jurisdiction under the Federal Power, Natural Gas or Natural Gas Policy Acts, with disputes elevated from staff to directors and ultimately to the respective commissioners.  While the jurisdictional MOU imposes these obligations on the Participating Agencies, it expressly creates no private right of action that could be enforced by a regulated company or other third party.

The MOU on information sharing obligates the Participating Agencies to share information needed in connection with each other’s market surveillance or investigations into suspected manipulation, fraud or market power abuse in markets that the requesting Participating Agency regulates.  FERC is authorized to seek from the CFTC information from (1) designated contract markets, (2) registered swap execution facilities, (3) registered derivatives clearing organizations, (4) boards of trade and (5) market participants.  The CFTC, on the other hand, is authorized to seek from FERC information from (1) regional transmission organizations or independent system operators, (2) the North American Electric Reliability Corporation, (3) interstate natural gas pipelines and storage facility operators, and (4) market participants.  Specific provisions of the MOU obligate both Participating Agencies to take all actions reasonably necessary to preserve, protect and maintain privileges and claims of confidentiality for non-public information.  Sharing information pursuant to the MOU expressly does not constitute a waiver of any privilege or protection attached to the shared information.

by Dan Watkiss

In a July 16 order, the Federal Energy Regulatory Commission (FERC) assessed civil penalties of $453 million against a British banking conglomerate (BCL) and four of its power traders for manipulating western electricity markets from from November 2006 to December 2008 in violation of the Federal Power Act (FPA) and Commission regulation 1c.2.  The bank has 30 days to pay its $435 million penalty and disgorge $34.9 million in profits plus interest from its manipulative trades; likewise, the traders have 30 days to pay penalties ranging from $1 million to $15 million each.  The bank announced that it will not pay and instead will contest the finding of market manipulation in federal court.  The penalties are among the highest FERC has ever assessed under the authority Congress conferred on it in 2005 to police market manipulation.

FERC’s Office of Enforcement launched its investigation of BCL in July 2007, culminating in an October 2012 FERC order directing the bank and its traders to show cause why they should not be found guilty of market manipulation and assessed penalties.  Following the investigation, FERC concluded that the bank and traders traded fixed price products not to profit from the relationship between the market fundamentals of supply and demand, but rather to move the daily Index Price in favor of BCL’s long or short financial swap positions at the four most liquid western trading locations:  Mid-Columbia, Palo Verde, North Path 15 and South Path 15. According to FERC’s July 16 order, Enforcement Staff’s investigation unearthed a trove of communications among the BCL’s traders describing the allegedly manipulative scheme and affirming their intent to effectuate it, including so-called “speaking” documents in which traders describe their efforts “to drive price,” “move” the Index and “protect” their swap positions.

As amended to include an anti-manipulation rule modeled on the Securities and Exchange Commission’s Rule 10b-5, the Federal Power Act and FERC’s implementing regulations prohibit an entity from: (1) using a fraudulent device, scheme or artifice to defraud or to engage in a course of business that operates as a fraud or deceit; (2) with the requisite intent; (3) in connection with the purchase, sale or transmission of electric energy subject to the jurisdiction of the Commission.  The Act also empowers FERC to assess a civil penalty of up to $1 million per day, per violation against any person who violates Part II of the FPA (including section 222 of the FPA) or any rule or order thereunder.  As it has in other prosecutions for market manipulation, FERC rejected BCL’s defense that “open market” trading is per se not manipulative.

The July 16 order is noteworthy not only for the amount of penalties FERC assessed, but also for the procedural history of the BCL investigation.  The bank and traders chose to forego their right to an evidentiary hearing before a FERC judge and instead had the Office of Enforcement’s proposed findings of manipulation submitted directly to the Commission for its determination.  The bank’s and traders’ claims that the statute of limitations had run or that Enforcement Staff was equitably estopped from making its allegations were not successful in convincing the government to drop the charges against them.

FERC must now seek to enforce its decision and collect the penalties and disgorgement in federal court.

by William Friedman

The Federal Energy Regulatory Commission’s (FERC) approval of the New York Independent System Operator’s (NYISO) demand response compensation program left out a mechanism for compensating demand response from behind-the-meter generation, which prompted the latest outcry from demand response providers.   The demand response providers filed a complaint with FERC claiming discrimination between methods of demand response and seeking to compel the NYISO to compensate behind-the-meter generation demand response.  On the other side of the controversy are power producers who fear that compensating behind-the-meter generation would take money from power generation on the other side of the meter.

Demand response is a reduction in electricity consumption by customers from their expected consumption in response to an increase in the price of electricity or incentive payments designed to induce lower consumption.  In Order No. 745, FERC established a compensation approach for demand response resources by requiring that each regional transmission organization (RTO) and independent system operator (ISO) pay a demand response resource the market price for energy when the resource has the capability to balance supply and demand and when doing so would provide a net economic benefit to consumers.

The NYISO’s Order No. 745 compliance filing was approved by FERC without providing for compensation to behind-the-meter generation.  In other words, consumers with behind-the-meter generation, usually large industrial facilities, will not be compensated for relying on their own generators as an alternative to purchasing power from the market, while other demand response resources that do not generate power will be compensated solely for decreasing consumption.  In response, a number of facilities and aggregators that provide demand response recently complained to FERC seeking an order compelling the NYISO to compensate behind-the-meter generation as part of its demand response program.  The complainants point to neighboring RTOs/ISOs, including ISO-NE, PJM and MISO, which do compensate behind-the-meter generation and argue that excluding behind-the-meter generation violates FERC policy and constitutes undue discrimination.

The demand response providers are opposed by a consortium of independent power producers who argue that including behind-the-meter generation is economically inefficient and creates an improper incentive to move generation behind the meter where it is outside the reach of the RTO/ISO.  The NYISO also filed an answer to the complaint, arguing that forcing the ISO to compensate behind-the-meter generation as a demand response resource raises grid reliability and monitoring concerns.  The NYISO states in its pleading that it is already exploring revisions to its demand response program and the ISO’s internal stakeholder process should be allowed to run its course.  Answers to the complaint were filed last week.  A FERC ruling should be handed down in two to three months.