FERC’s inquiry into MISO’s formula rate protocols began after several entities argued against the recovery of transmission rate incentives through formula rates during various proceedings at FERC (see May 21, 2012 edition of the WER).  FERC instituted an investigation and set the matter for paper hearing, stating that it was concerned about: (1) the scope of participation regarding who can participate in MISO’s information sharing process; (2) the transparency of the information exchange and what information is exchanged; and (3) the ability to challenge the TOs’ implementation of their formula rates.

In the Investigation Order, FERC noted that MISO’s formula rate protocols were among the first filed at FERC in 1998.  FERC stated that since that time, numerous other protocols have developed and evolved that offer various benefits to stakeholders.  FERC explained that these newer procedures generally offer a broad scope of stakeholder participation, increased access to additional information, and expanded procedures in which stakeholders can challenge the formula rate updates.

FERC directed MISO and the TOs to expand the formula rate protocols to allow for information exchange and review by all interested parties – including state utility regulatory commissions, consumer advocacy agencies, and state attorneys general – rather than just customers.  FERC also directed MISO and TOs to expand the amount of information and the level of detail within the information that they share with interested parties so that those parties can properly review and analyze the TOs’ formula rate calculations.  Lastly, FERC directed MISO and the TOs to revise both their pro-forma and company-specific formula rate protocols to outline structured procedures for formal and informal challenges to the TOs’ annual rate updates and true-ups, as appropriate.

MISO and the TOs must file revised formula rate protocols within 60 days of the date of FERC’s Investigation Order.  A copy of the Investigation Order is available here.

Order No. 779 requires NERC to develop proposed GMD reliability standards in two stages, each with set timing requirements.  In the first stage, NERC must file one or more reliability standards that require owners and operators of the Bulk-Power System to implement “operational procedures” to mitigate GMD effects that are consistent with the reliable operation of the Bulk-Power System.  FERC stated in its order that the operational procedures may help “alleviate abnormal system conditions due to transformer absorption of reactive power during GMD events.”  The Commission did not direct NERC to outline specific operational procedures, and indicated that it expects owners and operators of the Bulk-Power System to structure operational procedures in a way that fits their particular equipment and system.  NERC must file these proposed standards within six months of the effective date of Order No. 779.   In addition to the first stage of reliability standards, FERC also directed NERC to identify facilities that are most at-risk from a severe GMD and “conduct wide-area geomagnetic disturbance vulnerability assessment.”

For the second stage, FERC directed NERC to file proposed standards that require owners and operators of the Bulk-Power System to complete initial and on-going assessments of the “potential impact of benchmark GMD events on Bulk-Power System equipment and the Bulk-Power System as a whole.”  FERC specified that “benchmark GMD events” are the severity of GMD events that the responsible entities must look at for potential impacts.  FERC indicated that benchmark GMD events should be based on items like duration, geographic footprint of the GMD, and varying severity of GMD, among other items, yet FERC did not specify a benchmark GMD for NERC.   FERC also directed NERC to submit proposed reliability standards that require owners and operators to implement a plan for protection against: (1) instability; (2) uncontrolled separation; and (3) cascading failures from a benchmark GMD event and its impact on the Bulk-Power System.  FERC clarified that the second stage of GMD reliability standards should not impose “strict liability” on parties for failing to ensure reliable operation of the Bulk-Power System due to a “GMD event of unforeseen severity.”  NERC must submit the second set of proposed standards within 18 months of the effective date of Order No. 779.

Also on May 16, 2013, Commissioner LaFleur issued a separate statement regarding Order No. 779, highlighting “significant changes or clarifications” from the NOPR reflecting comments the Commission received.  Commissioner LaFleur noted that Order No. 779 does not prescribe a specific technology or methodology for the standards in the second-stage of the NERC process, nor impose “strict liability” for outages caused by GMD events of “unforeseen severity.”  Commissioner LaFleur thanked NERC, the industry, and other stakeholders for their work to help better understand GMD events.

A copy of the final rule is available here.

Also on May 16, 2013, the Senate Environment and Public Works Committee approved the nomination of Gina McCarthy to be the next Administer of the Environmental Protection Agency (“EPA”) with a 10-8 vote.  Ms. McCarthy’s nomination will now proceed to the Senate floor where the full Senate will vote on her nomination.  No date has been set for the vote.  Ms. McCarthy currently serves as EPA’s assistant administrator for the Office of Air and Radiation.

A record of the vote on Dr. Moniz’s confirmation is available here.

Linden operates as a merchant transmission provider, and in 2007, signed Transmission Scheduling Rights Purchase (“TSR”) Agreements with Brookfield and Cargill for transmission rights on its line.  The TSR agreements contained the price per kilowatt month and all non-price terms and conditions.  However, prior to the execution of the TSR agreements, PJM Transmission Owners filed proposed tariff revisions to allocate costs of transmission upgrades to merchant transmission providers.  Then, in 2009, Linden filed tariff provisions that allowed Linden to charge holders of firm transmission rights any transmission upgrade costs that PJM allocated to Linden.  Following FERC approval of these tariff revisions, Linden began charging Cargill and Brookfield a pass-through charge for PJM transmission service costs that was initially charged to Linden.

Cargill and Brookfield disputed these charges and filed an action in federal district court.  Linden countered and filed a complaint and petition for declaratory order with FERC.  On February 27, 2013, the district court held that it would abstain from ruling on the petition until FERC had addressed the complaint.

In its complaint, Linden argued that the language of the TSR Agreements expressly allowed for pass-through of PJM transmission upgrade costs from Linden to Cargill and Brookfield, and the history of the PJM tariff prove FERC’s intent to have such customers pay these costs.  Specifically, Linden argued that the TSR Agreements incorporate by reference sections of the PJM tariff that make customers such as Cargill and Brookfield responsible for transmission upgrade costs when passed through.  Additionally, Linden argued that schedules 14 and 16 of the PJM tariff detail the manner in which PJM may allocate upgrade costs to a merchant facility, and that those costs may be passed on from a merchant facility to a customer.

In their answer, Cargill and Brookfield countered that Linden may only pass through upgrade costs when there is contractual authority to do so, and no such contractual authority exists.  Cargill and Brookfield argue that the TSR Agreements list all payment obligations required of them, and there is no requirement to pay for transmission upgrade costs.  Therefore, Cargill and Brookfield argue that the inclusion of specific payment obligations implies that the only payment obligations are the ones listed, and excludes any payment for items not listed.

FERC agreed with Cargill and Brookfield and rejected Linden’s complaint.  In its order, FERC stated that the only payment obligations are contained solely in within the TSR Agreement and may not be incorporated by reference.  FERC continued, stating that “the very essence of a negotiated rate contract” is that a party is at risk for either overpayment or undercollection of negotiated coasts, and cannot create any additional costs that were not originally contained within the contract.  Furthermore, FERC stated that while Linden was aware of the risks of the proceeding, but Linden chose not to include an express provision within the TSR Agreement to later allocate pass-through charges it received from PJM to its customers.  Instead, FERC noted that Linden chose to rely on its negotiated rate as sufficient to cover any “potential risk of exposure to transmission cost increases.”  Therefore, FERC held that “there is no language in the TSR Agreements that persuasively supports Linden VFT’s position that the TSR Customers are contractually obligated to pay the PJM Transmission Service Costs.”

A copy of the order is available here.

The meeting will be held on May 16, 2013 at FERC headquarters in Washington, DC from 1:30pm to 3:30pm.  Any interested party may attend the meeting without first registering, or watch via FERC webcast.  According to the notice, Commission members will be present.  A copy of the notice detailing the meeting agenda and listing its presenters is available here.

The Technical Conference will be open to the public in the Commission Meeting Room at FERC’s Washington DC headquarters and also available online via webcast at www.ferc.gov.

A copy of FERC’s notice is available here.

Under PJM’s tariff and the Reliability Pricing Model (“RPM”) capacity market rules, there are three DR products that can participate in the RPM capacity auction: (1) Annual DR; (2) Extended Summer DR; and (3) Limited DR.  Each product has limits on the hours of the day when it must be available, with Limited DR as the most restricted.  PJM’s Tariff currently employs two tests to set a “maximum amount of Limited Demand Resources determined by PJM to be consistent with the maintenance of reliability…”  According to PJM’s filing, the Limited DR Reliability Target helps PJM determine the level of Limited DR products that would cause PJM to pay higher prices to less restricted resources, to “induce” commitment of those less restricted resources and lower PJM’s reliance on Limited DRs.

PJM’s tariff revisions include an establishment of a third test to determine the Limited DR Reliability Target, to ensure that the “probability of requiring an interruption of longer than six hours is minimal.”  The Commission found that PJM’s additional test would “enhance” PJM’s evaluation of the Limited DR Reliability Target and “minimize” the risk of potential reliability concerns from relying on the Limited DR, a resource is not required to respond after six hours of interruption.

A copy of the Commission’s Order is available here.

The Senators stated that the Dodd-Frank Wall Street Reform and Consumer Protection Act divides the jurisdiction of the natural gas markets with FERC regulating the physical cash market, and the CFTC regulating the futures market.  However, the Senators noted that effective regulation in these markets requires “active oversight of both markets in an integrated fashion,” and that the recent Brian Hunter dispute has undermined the regulation of these markets.

The Senators’ letter focused on the lack of cooperation between FERC and the CFTC, highlighting the recent jurisdictional dispute and lack of agency cooperation.  Specifically, the letter addressed concerns that the two agencies only shared information when a specific request was made – a process that the Senators noted could take months – and that the agencies’ different methods of information collection impeded cooperation during investigations by making “it more difficult for either Commission to identify market distorting conduct.”

Therefore, the Senators requested that FERC and the CFTC comply with Section 720 of Dodd-Frank by agreeing to new MOUs that promote cooperation between the agencies, increased information sharing, and integration of all natural gas and electricity trading information between the agencies.

Commissioner Phillip Moeller, speaking at an industry event, noted that “the two agencies could certainly benefit from having a better working relationship.”  A copy of the Senators’ letter is available here.

In 2009, FERC’s Office of Energy Projects found that Seneca Falls was in violation of its hydropower license and issued a compliance order; Seneca Falls appealed the compliance order to the Commission.  FERC affirmed the violations and referred the matter to the Office of Enforcement (“Enforcement”) “for consideration of appropriate action.”  Upon investigation, Enforcement concluded that Seneca Falls had violated the terms of its license by failing to: (1) obtain sufficient property rights; (2) file and execute a plan to monitor wetland vegetation in a timely manner; (3) install a car-top boat launch in a timely manner; (4) maintain a consistent seasonal level of the Barge Canal Datum; (5) design and install fish passages in a timely manner; and (6) study the effectiveness of the fish passages.

According to the Settlement, Seneca Falls has already fully or partially remedied some of the violations Enforcement found during its investigation.  In addition to the monetary obligations, Seneca Falls must submit semi-annual compliance reports to FERC until all violations are remedied.

Seneca Falls stipulated to the facts in the Settlement, but neither admitted nor denied the violations.  A copy of the Settlement is available here.

As designed, the 330-mile transmission line will be constructed primarily underneath Lake Champlain and the Hudson River, in order to minimize the potential environmental impacts of the line.  Construction of the Champlain-Hudson line is estimated to cost $2 billion.  However, the NYPSC noted that ratepayers are not required to assume the financial risks associated with construction of the line.  Instead, the Champlain-Hudson line is a “merchant” project, and the Federal Energy Regulatory Commission has already approved the use of negotiated rates for the sale of capacity on the line (see July 9, 2010 edition of the WER).

The approval of the Champlain-Hudson line is the result of three years of negotiations between Champlain Hudson Power Express, Inc. and CHPE Properties (“Applicants”), numerous state agencies and cities in New York, and several environmental advocacy groups, and other interested parties (see April 23, 2010 edition of the WER).  The NYPSC hailed the parties’ ability to reach a consensus on the line as a “remarkable achievement.”  With respect to the converter station that the direct current line needs in order to be connected to the alternating current bulk power system, that facility will be located in Astoria, Queens, under the terms of the NYPSC’s approval.

In approving the Champlain-Hudson line, the NYPSC highlighted that the new transmission line will offer significant benefits to New York City.  Specifically, the NYPSC stated that the line will enhance fuel diversity, create stronger transmission ties into New York City, increase the state of New York’s utilization of renewable energy sources, and reduce the possibility of existing suppliers exercising market power.  In addition to the construction of the line, the Applicants agreed to establish a $117.15 million trust for the restoration and enhancement of the Lake Champlain and Hudson River habitats.

On April 23, 2013, the Applicants responded to the NYPSC’s approval of the Champlain-Hudson line and accepted and agreed to comply with all conditions of the NYPSC’s Certificate of Environmental Compatibility and Public Need.

A copy of the NYPSC’s order is available here.