Ill. AG Joins Call for Changes to MISO Auction Rules

By Chris O’Malley

Illinois Attorney General Lisa Madigan last week joined industrial consumers in calling for changes to MISO’s capacity auction rules, while the RTO defended itself, in filings with federal regulators.

MISO’s rules “are no longer just and reasonable and require modification,” Madigan said in comments filed July 20 with the Federal Energy Regulatory Commission (EL15-82). Madigan said last week that she supports proposals the Illinois Industry Energy Consumers made in a June 30 filing.

In May, the attorney general and Public Citizen filed complaints asking FERC to investigate Dynegy’s bidding behavior in April’s Planning Resource Auction, which resulted in a nine-fold price increase for Zone 4 (EL15-70).

IIEC said last May’s auction — which saw Zone 4 clear at $150/MW-day compared with just $16.76 a year earlier — will cost Illinois industrial companies $1.6 million each, on average. Madigan said the dramatic swing in auction prices also hurts Illinois’ residential ratepayers.

“While the people did not propose specific Tariff changes in their complaint, the changes recommended by IIEC address some of the issues raised in the people’s complaint and are necessary revisions to ameliorate the effects of market power in the MISO zones, and particularly in Zone 4,” Madigan said.

Industrials and Madigan say the idea that Dynegy’s bids are justified by the opportunity cost of selling power into PJM is specious. IECC said there is little transmission capacity and “very few” bilateral sales between MISO and PJM. That, Madigan said, calls “into question the existence of the opportunity to sell to PJM at the prices reflected in the initial reference level.”

The initial reference level is set “as if there were no limits on the transmission of MISO-generated megawatts in the PJM areas,” Madigan said.

Citing FERC’s Electric Quarterly Reports, consultant Robert McCullough, a witness for the state, said that prices of the few bilateral sales from MISO to PJM were low — with one at only $1.09/MW-day.

MISO Response

In a response filed July 20 (EL15-82), MISO said the IIEC comments “misapprehend” the concept of opportunity costs.

MISO said IIEC suggests that the RTO may only calculate an opportunity cost prior to the PRA based upon “having perfect knowledge” — not only of resources’ bids into MISO’s auction, but also of bids into PJM’s market.

“Then, MISO is somehow expected to create a clearing price for markets in both PJM and MISO based upon such perfect knowledge,” MISO shot back. “Obviously, this standard is impossible to meet and unnecessary to properly estimate a supplier’s opportunity cost.”

MISO also countered that IIEC’s proposal would result in double-counting resources and incentivize suppliers to not make offers into MISO, “which will lead to a less robust market and potentially higher prices.”

Confidentiality Needed

IIEC and Madigan said FERC should also reconsider how the initial reference level is communicated to generators. In Illinois’ auctions for default electric service, the market administrator determines a benchmark price, but it is kept confidential so that bidders base their offers on their own costs rather than pegging them to a higher level, Madigan said.

“In revising the MISO Tariff, the commission should require that the reference level be maintained as confidential so that bidders cannot structure their bids around the reference level,” Madigan said. “While a reference price that is properly established may be a useful tool to address market power, MISO’s Tariff perverts the role of the reference price from a meaningful cap to an instrument of market power.”

Counter-Flow Concerns

Finally, the attorney general supports another revision to MISO’s Tariff recommended by IIEC: reducing the local clearing requirement (LCR) by the amount of capacity exported into a neighboring market. They say that an LCR that is too high creates more opportunity for a large generator to exercise market power.

Madigan cited the Independent Market Monitor’s 2014 State of the Market report, which stated that the binding of the LCR in Zone 4 was impacted by about 1,200 MW exported from Zone 4 to PJM. The Monitor recommended that MISO file Tariff revisions to treat local capacity exports “as creating counter flow over the interface” into the zone.

“This would cause the capacity to be replaced by the lowest-cost capacity from any area in MISO, rather than requiring that additional capacity be procured from within the zone,” the Monitor wrote.

IIEC filed testimony claiming that if the 1,200 MW of exported capacity had been excluded from the LCR, the pivotal supplier’s opportunity to exercise market power would have been limited to $8/MW-day, compared to the $150/MW-day Dynegy received in the April auction.

‘Simply Incorrect’

MISO countered that IIEC “is simply incorrect” in stating that MISO fails to account for counter flows when it calculates each zone’s LCR. MISO said it has properly accounted for resources in one zone that are sold into another capacity market when it calculates each zone’s capacity import limit, which is used to establish the LCRs.

Subsequently counting zonal resource credits again when calculating the LCR would amount to double-counting a resource, MISO said.

“Artificially lowering the local clearing requirement would threaten resource adequacy in the MISO region and unjustly and unreasonably suppress capacity prices,” the RTO said.

Original Complaint

Meanwhile, the attorney general and Public Citizen have made filings asking FERC not to dismiss the complaints they filed in May, as Dynegy, NRG Energy and the Electric Power Supply Association have requested.

Market Monitor David Patton and MISO have joined Dynegy in denying allegations of improper conduct in last April’s auction. (See Dynegy: No Evidence of Misconduct in Auction.)

July 28, 2015

NYPSC Opposes NYPA Tx Rate Hike Request

By William Opalka

The New York Public Service Commission has come out against the New York Power Authority’s bid for a nearly 10% increase in its transmission rates, saying its requests for an adder for ISO participation and use of a 60% equity capital structure are excessive.

The Power Authority asked the Federal Energy Regulatory Commission on June 2 for approval of a formula rate including a 50-basis-point adder to its return on equity for participation in NYISO and permission to base its ROE on a capital structure with 60% equity. It also sought recovery of its costs for a transmission project to address reliability concerns if the Indian Point nuclear power plant is closed.

The proposal, which includes a base ROE of 8.85%, would increase the organization’s annual transmission revenue requirement by approximately 9.6%, from $175.5 million to $192.4 million, effective Sept. 1.

The PSC said in a filing last week that the adder for participation in NYISO “is unnecessary and unwarranted” because the authority has already agreed to turn operational control of its transmission facilities over to the ISO (ER15-2102).

Regulators said the requested capital structure also is excessive and unnecessary “since a 50% equity ratio would adequately balance collections from customers and ensure that the utility has access to capital markets at reasonable terms.”

The PSC also said FERC should defer action on proposed performance-based incentives regarding the Marcy-South Series Compensation (MSSC) project, pending resolution of settlement discussions in a separate docket.

ISO Participation Adder

The NYPSC said the ROE adder for participation in NYISO is unnecessary.

The PSC said it supports ROE incentive adders “that truly provide consumer benefits, such as encouraging the use of innovative technologies or providing congestion relief. … An additional incentive for NYISO participation is not justified where the commission’s goals of incentivizing the creation of the NYISO and transferring operational control of their transmission facilities to the NYISO have already been achieved. Awarding NYPA an ROE incentive for what it must do in any event is not warranted since the incentive will have no effect on its behavior.”

Capital Structure

The PSC also said NYPA’s equity ratio should be limited to 50%, consistent with utilities similar to the authority.

The PSC said ratepayers would also pay excessive costs to maintain NYPA’s “exceedingly strong” credit rating. Its equity ratio as of 2014 was 76.4%. The PSC notes that Moody’s Investors Service has called the authority’s debt ratio “one of the lowest of any major U.S. public power electric utility with generation.”

The PSC said the authority’s proposal to cap its equity at 60% “incorrectly suggests that the costs associated with maintaining these high-end financial metrics do not come at an increased cost to ratepayers, relative to investor-owned utilities.”

“While NYPA has certain tax advantages over investor-owned utilities, having financial ratios in the Aaa-range come at a cost to ratepayers due to an overall increase in equity costs. All else equal, NYPA could collect less from ratepayers while maintaining its metrics in the ‘Aa’ range. … Slightly lower credit metrics, due to a lower equity ratio, will in no way hinder NYPA’s ability to raise capital on reasonable terms.”

Marcy-South

The PSC also challenged as “premature” the authority’s request for recovery of its costs if the Marcy-South project is abandoned for reasons outside the NYPA’s control.

The MSSC project is one of the Transmission Owner Transmission Solutions (TOTS) projects being developed by the authority and New York Transmission Co. as a result of recent PSC proceedings to address reliability concerns over the potential retirement of Indian Point.

The authority said it intended to “include the same risk-sharing or performance-based incentive components that are ultimately agreed to by the NY Transco in Docket No. ER15-572 with respect to future competitive projects.”

The PSC said that because of the overlapping issues between the two dockets, FERC should defer the issue pending the outcome of the NY Transco proceeding.

July 23, 2015

FERC Orders PJM to Include DR, EE in Transition Auctions

By Rich Heidorn Jr.

PJM will delay the transition auctions for the new Capacity Performance regime to comply with a Federal Energy Regulatory Commission order that the RTO include demand response and energy efficiency.

FERC ruled 4-1 late Wednesday that the auctions, which were set to begin July 27, would not be just and reasonable without permitting DR and EE resources to participate. PJM must make a filing within 15 days describing how it will comply with the order and setting a new schedule.

The commission ruled in response to a joint complaint by the PJM Industrial Customer Coalition, environmentalists and regulators or consumer advocates from Delaware, D.C., New Jersey, Maryland, Pennsylvania, Illinois and West Virginia. A coalition of DR providers had filed a separate challenge to PJM’s exclusion.

New Schedule

Stu Bresler, senior vice president of market services, told the Markets and Reliability Committee on Thursday morning that the RTO will schedule the transition auctions after the Base Residual Auction Aug. 10-14.

The transition auction for 2016/17 had been set for July 27-28 and that for 2017/18 for Aug. 3-4. In a filing Tuesday, PJM set the 2016/17 auction for Aug. 26-27, with results posting on Aug. 31. The transition auction for the 2017/18 delivery year will be held Sept. 3-4, with results posted on Sept. 9.

PJM had said the transition auctions were designed to “provide a glide path” for generation resources that needed time to make investments to meet Capacity Performance requirements and were not necessary for other resources. PJM also said it was concerned about the continuing uncertainty following the D.C. Circuit Court of Appeal’s EPSA ruling voiding FERC Order 745, which set compensation rules for the resource in RTO energy markets.

FERC said, however, that Tariff provisions barring DR and other non-generation resources from participating in the transition auctions were “unduly discriminatory as applied to technically capable resources willing to perform as a Capacity Performance resource” (ER15-623, EL15-29).

Similarly Situated

“PJM has failed to provide an adequate explanation … as to how non-generation resources are not similarly situated to generation capacity resources for purposes of providing the capacity services PJM plans to procure through the transition auctions,” FERC continued.

The commission rejected PJM’s argument that participation in the transition auctions should be limited to resources that need to make investments to meet performance and fuel assurance requirements. “The purpose of the transition auctions is to procure a more reliable portfolio of capacity resources, and we see no basis for excluding non-generation resources capable of providing that service from participating,” the commission said.

FERC also dismissed PJM’s attempt to justify the prohibition on DR on the uncertainty over FERC’s jurisdiction. The commission’s appeal of the EPSA ruling is now pending before the Supreme Court.

The commission noted that it had previously rejected similar arguments as premature. It also observed that DR and EE resources selected in prior auctions are still expected to deliver on their capacity commitments. (See FERC: PJM Demand Response Stop-gap Measure ‘Premature.’)

The commission said PJM must file revisions to Attachment DD of its Tariff to allow all resources that qualify as Capacity Performance to participate in the transition auctions.

In its response to the complainants, PJM offered two alternatives for including DR and EE in the auctions, saying the “less risky” option would be to limit participation to previously cleared resources.

FERC said neither option was sufficient because they would bar participation in the auctions by DR and EE that did not previously submit sell offers for the delivery year.

“PJM’s current [Tariff] does not place such restrictions on generation capacity resources, and the commission finds that PJM has failed to support a disparate treatment of other Capacity Performance resources in its proposed alternatives,” FERC said.

Dissent

Commissioner Tony Clark dissented, saying the order was improper procedurally because the commission had previously approved “unambiguous” Tariff language barring DR and EE from the auctions.

“It is not PJM’s burden to now prove that an already agreed on transition incremental auction methodology is just and reasonable. Rather, it is complainants’ burden to explain why now, just weeks after the commission’s Capacity Performance order and just days before the first transition incremental auction, the plain Tariff reading of Attachment DD, section 5.14D(B)(3) is unjust and unreasonable.”

Commissioner Philip Moeller responded in a concurring statement. “While a close reading of PJM’s proposed Tariff provisions indicates that non-generation resources would be excluded from participation in the transition auctions, PJM’s voluminous filing did not make this fact, or its underlying justification, clear to PJM stakeholders or the commission,” Moeller wrote.

“PJM initially represented that its Capacity Performance proposal ‘preserves its current approach’ to demand response participation, in contrast to its more recent position that it intended to limit non-generation resource participation in the transition auction due to the uncertainty surrounding EPSA.”

Clark also said he agreed with PJM’s call for caution in the handling of DR because of the legal uncertainty.

“Rather than proclaiming, ‘damn the torpedoes, full speed ahead!’ I would prefer a modest approach whereby we avoid buying ourselves more potential trouble and refrain from actively adding more demand response megawatts into PJM’s capacity construct while it faces an uncertain future and possible disorderly ‘unwinding.’ While the pendency of Order No. 745 is not alone dispositive, it should cause us to proceed more cautiously than we are doing here.”

July 21, 2015June 15, 2023

FERC Seeks Supply Chain Protection Against Cyber Threats

By Michael Brooks

Two malware campaigns against vendors of industrial control systems have prompted the Federal Energy Regulatory Commission to propose the development of a new reliability standard.

FERC issued a notice of proposed rulemaking last week that directs the North American Electric Reliability Corp. to develop critical infrastructure protection (CIP) rules for supply chain management to respond to risks to communication networks and related Bulk Electric System (BES) assets (RM15-14).

“This new type of malware campaign is based on the injection of malware while a product or service remains in the control of the hardware or software vendor, prior to delivery to the customer,” FERC said. The supply chain rules would be part of a revised standard, CIP-006-6 (Physical Security of BES Cyber Systems).

The NOPR seeks comment on that and six other updated CIP standards.

Trojan Horse Viruses

The two malware threats that prompted FERC’s concern are Trojan horse viruses planted in industrial control systems, such as supervisory control and data acquisition (SCADA) and programmable logic controllers (PLCs). One, called Havex, was identified in June by cybersecurity firm F-Secure and was used to conduct espionage against several industrial companies in Europe.

Last fall, the Department of Homeland Security’s Industrial Control Systems Cyber Emergency Response Team (ICS-CERT) issued a warning that a Trojan horse virus dubbed BlackEnergy had been found on Internet-connected human-machine interfaces (HMIs) from vendors including GE Cimplicity, Advantech/Broadwin WebAccess and Siemens WinCC. ICS-CERT also cited public reports of a BlackEnergy campaign against overseas targets that took advantage of vulnerabilities affecting Microsoft Windows and Windows Server 2008 and 2012.

The virus is believed to have been planted as early as 2011 but only activated recently by government-backed hackers in Russia.

Third Time

Highlighting the seriousness of FERC’s concern, Commissioner Cheryl LaFleur noted that the NOPR represented only the third time the commission has ordered NERC to initiate a standard. FERC previously ordered standards addressing geomagnetic disturbances and physical security.

“The work that NERC, the industry and the commission do on cybersecurity must obviously continually evolve to meet the changing nature of the cybersecurity threat, which we all see in the news practically daily,” LaFleur said in a statement. “Understanding the evolving threats and how best to respond to them is of critical importance.”

The NOPR only gave NERC general directions as to what the new standard should include. The commission suggested it could be based on the National Institute of Standards and Technology’s supply chain risk management controls (SP 800-161). The Department of Energy also has offered guidance on cybersecurity procurement for energy delivery systems.

“It’s too early in the process to say what a standard might say or what the terms of it might be,” FERC Chairman Norman Bay said.

The order is intended to protect against malware and other supply chain risks including counterfeits and tampering or theft of data.

The new standard would only apply to registered entities subject to NERC jurisdiction, not vendors supplying them. “At this time we aren’t seeking some sort of broader statutory authority,” Bay said.

“While the commission’s CIP standards don’t specifically cover … supply chain vendors, there is undoubtedly a gap and vulnerability there that’s been identified now for some period of time that I think all of us take very, very seriously,” Commissioner Tony Clark said. “I suppose the main idea is that we’re trying to ensure that security becomes effectively baked into the cake, as it were, from the ground up in the systems that the electric utilities use.”

The commission asked for comment on the proposed standard, including what would be “a reasonable time frame” for its completion. Comments are due in 60 days from publication of the NOPR in the Federal Register.

Transient Devices

While FERC accepted most of the CIP standards as proposed, the commission ordered NERC to provide additional justification for its rules regarding risks posed by “transient” electronic devices such as USB flash drives and laptops.

The commission said it was concerned about NERC’s decision not to include rules regarding use of transient devices on “low-impact” cyber systems, including low-impact control centers.

“Malware inserted via a USB flash drive at a single low-impact substation could propagate through a network of many substations without encountering a single security control under NERC’s proposal,” FERC said. “In addition, we note that low-impact security controls do not provide for the use of mandatory anti-malware/antivirus protections within the low-impact facilities, heightening the risk that malware or malicious code could propagate through these systems without being detected.”

Nonprogrammable Components

The commission also said it was concerned that NERC’s standards provided limited protection for nonprogrammable components of communication systems, such as cabling.

NERC has proposed physical access restrictions and encryption as protections against physical attacks on nonprogrammable equipment, session hijacking attacks within a BES control center and man-in-the-middle attacks — in which an attacker intercepts and may alter data between two parties who believe they are directly communicating with each other.

But it “does not extend protections to real-time data passing between control centers outside of a facility,” FERC said.

The commission ordered NERC to modify CIP-006-6 to require protection of all communication links and sensitive data communicated between all BES control centers.

Other Standards

The other standards tentatively approved by FERC were: CIP-003-6 (Security Management Controls); CIP-004-6 (Personnel and Training); CIP-007-6 (Systems Security Management); CIP-009-6 (Recovery Plans for BES Cyber Systems); CIP-010-2 (Configuration Change Management and Vulnerability Assessments); and CIP-011-2 (Information Protection).

July 21, 2015

DTE Electric Wins OK to Acquire Gas Peaker

By Chris O’Malley

DTE Electric has won federal approval to acquire a 320-MW natural gas-fired peaking plant from its parent company to help it meet MISO Zone 7 resource adequacy requirements.

The East China peaking station is an indirect, wholly owned subsidiary of DTE Energy, the parent of DTE Electric.

The Federal Energy Regulatory Commission last week asserted that the deal won’t have an adverse effect on competition, saying it amounts to a transfer of generating assets between affiliated entities (EC15-138).

The East China facility was the only resource to respond to DTE Electric’s requests for proposals for simple-cycle generating facilities to meet its reliability requirements.

FERC said the RFP satisfied any concerns over cross-subsidization. “In the context of an acquisition of affiliated generation, a competitive solicitation is the most direct and reliable way to ensure no affiliate preference,” FERC said.

DTE Electric owns and controls about 13,479 MW of generating capacity, plus 4,000 miles of distribution lines. It is the provider of last resort for customer load in its territory.

The East China plant is authorized to make wholesale sales of energy and capacity at market-based rates.

Financial details of the acquisition were not specified.

Last fall, DTE Energy and Consumers Energy warned of a shortage of generation reserves starting next year, noting nine coal-fired plants in Michigan are set for retirement ahead of tighter air pollution regulations.

Consumer groups have accused the utilities of fear-mongering, saying further deregulation of Michigan’s electric market would help ensure the flow of additional power from elsewhere.

July 21, 2015

PJM Markets and Reliability Commitee Preview

Below is a summary of the issues scheduled to be brought to a vote at the Markets and Reliability Committee on Thursday. Each item is listed by agenda number, description and projected time of discussion, followed by a summary of the issue and links to prior coverage in RTO Insider.

RTO Insider will be in Wilmington covering the discussions and votes. See next Tuesday’s newsletter for a full report.

Markets and Reliability Committee

2. PJM Manuals (9:40-9:55)

Members will be asked to endorse the following manual changes:

A. Manual 01: Control Center and Data Exchange Requirements — Major update and reorganization to Section 5 introducing definitions of two major data types: System Control and Monitoring (Instantaneous) and Billing (Accumulated). Also updates references to OASIS and adds requirements regarding synchrophasor data exchange.

B. Manual 13: Emergency Operations — Includes administrative changes, clarifications and updates. Adds reference to Manual 12 for member actions when PJM loads 100% synchronized reserves and a reference to the instantaneous reserve check process.

3. CAPACITY PERFORMANCE (9:55-10:45)

A. Manual 18: PJM Capacity Market — Updates the manual to incorporate Capacity Performance. Includes clarifications on non-performance assessments, acceptable replacement resources for CP and Base Capacity commitments, the CP effective date for Fixed Revenue Resource entities and the physical option for non-performance for FRR entities. (See PJM Delays Vote on Capacity Performance Rules.) Members endorsed an update to Section 4.8 of the manual regarding credit requirements at a special MRC meeting July 15. Relevant forms have been posted for member use.

B. Manual 20: PJM Resource Adequacy Analysis — Changes related to the determination of limited-availability resource constraints under Capacity Performance. Because Capacity Performance rules allow participation of limited availability resources for the 2018/19 and 2019/20 delivery years, constraints must be established on Base Capacity DR and Base Capacity generation to ensure reliability. Details of the constraint computation methodology were added as Section 6.

4. FERC Order 1000 Proposal Fee Update (10:45-10:55)

Members will be asked to approve a two-tiered fee schedule for proposed transmission projects. For greenfield projects or upgrades between $20 million and $100 million, PJM will assess $5,000 to cover its study expenses. Projects costing at least $100 million will be charged $30,000. Previously, a $30,000 fee for all projects greater than $20 million had been approved, but planners later realized they likely wouldn’t need to collect that much. (See PJM Lowers Proposed Tx Project Study Fee.)

5. MERCHANT NETWORK UPGRADE (10:55-11:10)

New tariff language is being proposed to more accurately reflect how PJM processes requests for merchant network upgrades. The changes address definitions, queue entry, agreements and the capacity market.

6. TIMING OF REPLACEMENT CAPACITY TRANSACTIONS (11:10-11:25)

Manual changes would allow market participants to enter replacement capacity transactions earlier than Nov. 30 prior to the start of the delivery year if the need is linked to a physical reason that would prevent a participant from meeting its commitment. The changes prohibit generation that is replaced early from being recommitted for the delivery year. (See Earlier Replacement Capacity Transactions Approved.)

7. MARKET DATA CONFIDENTIALITY CLARIFICATIONS (11:25-11:40)

Members will be asked to approve a problem statement and issue charge designed to relax confidentiality rules regarding uplift payments and generator outages. Stakeholders have requested more granular data, especially following severe weather events. Current rules allow the release of aggregate market data only if it includes information about at least three market participants and it is no more specific than a PJM transmission zone. PJM also is prohibited from releasing data that already has been made public elsewhere. As a result, it’s unable to be more specific about such issues as conditions surrounding weather events, closed-loop interfaces and transmission planning. PJM also is offering a proposed solution. (See PJM Considering Release of Uplift, Outage Data.)

8. REGULATION MARKET ISSUES (11:40-12:00)

The Independent Market Monitor will seek approval of a problem statement and issue charge on concerns that PJM is buying too much fast-responding RegD resources in the regulation market. The initiative also will consider changes to the marginal benefit factor that defines that substitutability between RegA and RegD megawatts, which the Monitor says is faulty. (See PJM Market Monitor: Faulty Marginal Benefit Factor Harming Regulation.)

9. MARKETS RELATED GOVERNING DOCUMENTS UPDATE (12:45-1:00)

The PJM Law Department is proposing an initiative to clean up language in the RTO’s governing documents that is “ambiguous, incorrect or requires clarification.” PJM’s proposed problem statement and issue charge would assign the task to the Market Implementation Committee, separating it from an effort already underway involving the Tariff Harmonization Senior Task Force. (See PJM Law Proposes Cleaning up Language in Governing Documents.)

10. FTR/ARR TASK FORCE (1:00-1:15)

Old Dominion Electric Cooperative will seek approval for a proposal that combines recommendations from PJM and the Independent Market Monitor in redesigning the financial transmission rights and auction revenue rights process. (See ODEC Seeks Last-Ditch Vote on Deadlocked FTR/ARR Issue.)

11. TARIFF HARMONIZATION SENIOR TASK FORCE (1:15-1:30)

Members will be asked to approve seven revised definitions, the first batch of changes from the task force. (See Task Force Proposed to Resolve Inconsistencies in PJM Governing Documents.)

— Suzanne Herel

July 21, 2015June 15, 2023

FERC Eliminates Form 566 for Most Filers. So Why Does it Still Exist at All?

By Rich Heidorn Jr.

RTOs, ISOs and exempt wholesale generators will no longer have to file Form 566 (Annual Report of a Utility’s 20 Largest Customers), a minor but annoying requirement.

The Federal Energy Regulatory Commission eliminated the requirement for 82% of the current 1,082 filers in an order last week (RM15-3).

The commission noted that the report is intended to capture sales to end-use customers as opposed to those purchasing for resale. As a result, RTOs and ISOs have had to report only that they had no applicable sales. The same goes for exempt wholesale generators, which by definition cannot make retail sales.

FERC’s order computes down to the dollar the impact of the changes. Eliminating the requirement to provide the name and address of any residential customers will save 29 utilities 15 minutes each a year. In total, the rule change will save $390,312, FERC estimates.

But why did this rule exist in the first place? And what purpose does it serve today? Those answers are nowhere to be found in the 25-page order, which notes only that the form is the result of Section 305(c) of the Federal Power Act, dating to 1935.

FERC’s Frequently Asked Questions provides limited guidance, saying that the commission uses the form along with Form 561 (Annual Report of Interlocking Positions) to “determine whether public or private interests will be adversely affected by the holding of officer or director positions of both a public utility and its customers.”

Have the two forms ever uncovered any problems or resulted in enforcement actions? A FERC spokeswoman couldn’t say Monday.

FERC’s action exempts all but 196 of current filers, who are expected to spend a total of 1,071 hours annually on the paperwork at a cost of $77,094 (assuming an hourly cost of $72/hour).

FERC rejected the Edison Electric Institute’s request to extend the exemption to qualifying facilities or utilities participating in RTO and ISO markets. The commission said utilities participating in organized markets “may well also make sales ‘for purposes other than for resale.’”

“Adopting EEI’s suggestion would virtually eliminate the filing requirement, contrary to the statute,” FERC said.

The commission also declined to exempt transmission-only companies, but it said they may escape filing requirements because the commission is eliminating the reporting obligation for public utilities that make no reportable sales for the preceding three years.

It did, however, adopt EEI’s suggestion that it eliminate the requirement that utilities notify the 20 largest purchasers that their names are being reported.

July 21, 2015June 15, 2023

Federal Briefs

The Obama administration on Thursday toughened rules to protect waterways from coal mining by requiring mining activity to take place at least 100 feet from streams.

The administration said the updated regulations, which clarify earlier rules, require mines to monitor streams near their operations and call for companies to restore areas impacted by earlier operations. The Interior Department estimates that the rules will safeguard 6,500 miles of streams in the next 20 years.

Industry supporters denounced the new mandate. “It’s no secret that this overreaching rule is designed to help put the coal country out of business,” said Sen. John Barrasso (R-Wyo.). He called the regulation “job-crushing” and “anti-coal.”

More: National Journal

EPA Watchdog Says Agency Should Track Fracking Chemicals

The Environmental Protection Agency’s Office of Inspector General recommended the agency improve oversight of chemicals used in hydraulic fracturing. The OIG said the agency needed to crack down on the unlicensed use of diesel fuel in fracking and figure out whether to mandate public disclosure of fracking chemicals.

Although EPA’s oversight on fracking is limited by a 2005 law, it does have control over the use of fuels and chemicals that could affect the quality of drinking water. The agency has approved the use of diesel fuel in some fracking operations, but the OIG said there are instances where “EPA and primacy states have not been fully successful in their efforts to effectively control the use of diesel fuels for well stimulation.”

The OIG also said the agency should also address calls for the mandatory disclosure of chemicals used in fracking. “To date, however, the agency has not addressed the comments or developed a plan of action for the next steps,” the report said, adding that EPA “needs to develop an action plan with a timeline to address the public comments and determine whether to propose a rule to obtain information on chemical substances and mixtures used in hydraulic fracking.”

More: The Hill

Former DOE Official Tapped for NRC by Obama Admin

The Obama administration nominated a former Bush administration official to fill an empty seat on the five-member Nuclear Regulatory Commission.

If confirmed by the Senate, Jessie Hill Roberson, who served in the George W. Bush administration as an assistant secretary for environmental management, would be the third new commissioner on the NRC since September.

Roberson has been vice chairwoman and a member of the Defense Nuclear Facilities Safety Board for the last five years. She has held positions with several utilities, including nuclear-power giant Exelon.

More: Washington Examiner; Nuclear Energy Institute

NOAA, Others Say Oceans Hot and Getting Hotter

An annual report by the National Oceanic and Atmospheric Administration and the American Meteorological Society said the world’s oceans are warm and getting warmer.

According to the report, the ocean surface temperatures are the warmest in the 135 years that records have been kept. One reason: About 93% of the heat from burning fossil fuels goes into the oceans, which serve as giant heat sinks. The seas are holding record levels of thermal energy as deep as 2,300 feet below the surface.

The trapped heat in the oceans provides energy that feeds into tropical cyclones, according to NOAA oceanographer Greg Johnson. The report was compiled by more than 400 scientists.

More: Associated Press

Federal Judge Dismisses Oklahoma’s Second Lawsuit Against Clean Power Plan

A federal judge on Friday dismissed Oklahoma’s second attempt to block the Obama administration’s climate rule for power plants, saying the state cannot challenge the Environmental Protection Agency’s regulation until it becomes final.

“The court finds no exceptional circumstances that would warrant judicial intervention at this time, and plaintiff’s claims should be dismissed for lack of subject matter jurisdiction,” ruled U.S. District Court Judge Claire Egan of the Northern District of Oklahoma.

It is the second time in two months a federal judge has dismissed an Oklahoma challenge to the Clean Power Plan, both for similar reasons. EPA is expected to issue its final rule next month.

More: The Hill

July 21, 2015June 15, 2023

SPP Strategic Planning Committee Briefs

KANSAS CITY — SPP’s Strategic Planning Committee on Thursday endorsed a plan to make incumbent transmission owners responsible for providing cost estimates for non-competitive projects.

The plan recommended by the Competitive Transmission Process Task Force — Solution 2A — easily cleared the Markets and Operations Policy Committee earlier last week. It adds additional cost analysis of competitive-projects by transmission owners. SPP and third-party vendors would still evaluate competitive projects subject to Federal Energy Regulatory Commission Order 1000.

Although the overall timeline remains the same, Solution 2A adds three and a half weeks of study development, allowing for a better cost analysis, said Xcel Energy’s Bill Grant, the task force’s chair.

“For the projects that have been identified as non-competitive, we will receive the estimate from the transmission owner instead of the third-party vendor,” Grant said. “At this point in time, the project has already been selected. We’re just proving the estimate is non-competitive.”

Carl Monroe, SPP’s executive vice president and COO, said the additional screening “improves the estimating process, so we can give the [SPP] board better information” for selecting projects to build.

Because the process change could require revisions to the Tariff and governing documents, FERC approval will likely be required, along with the normal SPP approval process.

Load Responsibility White Paper

Golden Spread Electric Cooperative’s Mike Wise updated the SPC on the Capacity Margin Task Force’s Load Response Entity (LRE) white paper, which cleared the MOPC earlier in the week. The document is intended to ensure all load served by SPP’s balancing authority has sufficient capacity.

“If an entity is not responsible for a load forecast or contract,” Grant asked during the MOPC discussion, “should the customer be an LRE?”

“The first and most critical step is to make everyone adhere to the policy,” said Richard Ross of American Electric Power. “Secondly, we need to transfer the responsibility obligation to those with wholesale contracts. … It’s not my responsibility as a legacy BA.”

Developing a policy to enforce the requirement will take additional time, Wise said.

The task force asked that its charter be extended for an additional year to July 2016, a request approved by the MOPC and endorsed by the SPC.

Wise told the SPC that SPP staff is developing a deliverability study process that will allow for non-firm transmission service for planning reserves. The study will analyze all generators registered in the Integrated Marketplace and determine whether they are deliverable to all loads within the SPP balancing authority.

Engaging Prospective Members

The SPC also reviewed the final report from its Task Force on New Members and approved a recommendation to improve the process of engaging prospective transmission-owning and load-serving members.

The task force was commissioned in 2014 to develop formal processes to be followed during negotiations with prospective members.

Michael Desselle, SPP’s Chief Compliance and Chief Administrative Officer, said much of the task force’s work centered on how to involve the regulators on SPP’s Regional State Committee during the negotiation period. The task force tried to balance transparency with the need for confidential negotiations.

The report notes that SPP staff “remains solely responsible for the direct negotiations with the prospective member,” while stakeholders provide input on policy and changes to the governing documents.

The SPC discussed the legal costs for smaller entities and the threshold for “triggering events” when a prospective new transmission-owning member formally requests changes to SPP’s Tariff and governing documents or RSC bylaws.

The committee also considered the report’s definition of stakeholders: “Stakeholders include existing transmission owner members, transmission-using members and RSC members and their staffs.”

“Stakeholder means anybody and everybody in the world who feels affected in some way,” said SPP board member Phyllis Bernard, urging “SPP” be used as a modifier for “stakeholder” across all governing documents.

The task force will make several language modifications to the report before sending it to the SPP Board of Directors for its approval.

Behind-the-Meter Generation

Wise teed up a discussion on behind-the-meter generation by noting that the amount of such unaccounted-for energy is growing. “I know some market participants are not adding [behind-the-meter generation] back in[to the pool],” Wise said, “and it’s not fair.”

The Regional Tariff Working Group will take up the issue for further discussion during its Thursday meeting.

Integrated System

Monroe told the committee that SPP is continuing to incorporate members of the Integrated System and their facilities under the RTO’s Tariff. He said the majority of the IS load that would be placed under the Tariff has already been accounted for.

Monroe said that while the Northwest Power Pool has suspended its solicitation for bids to manage its energy imbalance service market, SPP continues to consult with the pool on EIS markets.

— Tom Kleckner

July 21, 2015

Plant Owner Responsible for Uncorrected ISO-NE Error, FERC Says

By William Opalka

The Federal Energy Regulatory Commission ruled Thursday that a power plant owner must pay unnecessary capacity charges because it failed to correct ISO-NE records before a deadline set by the RTO’s Tariff (EL15-57).

GenOn Energy Management, a unit of NRG Energy, asked FERC in April to excuse it from buying replacement capacity to meet an obligation it was capable of fulfilling with its own resources.

GenOn said ISO-NE credited its Canal 2 generator in Sandwich, Mass., with capacity of only 303 MW — rather than the plant’s actual 556.5-MW output — in the March Annual Reconfiguration Auction for the 2015-2016 capacity commitment period that began June 1. (See ISO-NE Error Could Cost GenOn Millions.)

ISO-NE said, and FERC agreed, that the Tariff requires participants to file restoration plans for any capacity shortfall within 10 business days after notification of the ARA results. “The provision also makes clear that after they receive notification of their qualified capacity from ISO-NE, the onus is on resources to provide a restoration plan, as necessary, and if they do not do so, ISO-NE will procure capacity on their behalf and charge them for it,” the commission wrote.

ISO-NE also said it wasn’t obligated to find out why no restoration plan was filed. (See ISO-NE: Plant Owner’s Responsibility to Flag Capacity Error.) FERC concurred. “We agree with ISO-NE that it is not ISO-NE’s responsibility to second-guess the market participant’s failure to submit a restoration plan after being notified of its qualified capacity,” it wrote.

The commission said reopening the auction as an alternative remedy would create market uncertainty.

In order to administer the capacity market, “ISO-NE must ensure that the auction results are final, and that, once the auction is concluded, market participants are able to take actions and enter into transactions immediately, based on those auction results,” it concluded.