Page 1538 – RTO Insider

June 30, 2015June 15, 2023

Federal Briefs

The House on Wednesday voted 247-180 to weaken the Environmental Protection Agency’s Clean Power Plan. The bill would delay implementation of the carbon emissions rules for power plants and would allow states to opt out of the rules.

“The bill’s effects would be felt hardest by those most at risk from the impacts of air pollution and climate change, such as the elderly, the infirm, children, native and tribal groups, and low-income populations,” the White House said in a letter to lawmakers. It promised that President Obama would veto the bill if it reached his desk.

Senate Republicans have introduced a similar bill that would go even further to weaken the rule and impair the EPA’s ability to set carbon rules for power plants.

More: The Hill

Federal Judge in Wyoming Grants Temporary Stop to Fracking Rules

A district court judge in Wyoming last week granted a request to temporarily stop new federal rules governing hydraulic fracturing on public lands.

Judge Scott Skavdahl granted a reprieve until July 22, acting on a request from the oil and gas industry, which said the rules represent an “arbitrary and unnecessary” burden on drillers. Industry was joined by state governments in Colorado, Wyoming, North Dakota and Utah in stopping the new rules.

The rules would require companies to disclose chemicals used in fracking on federal land and to implement new practices to curb oil and gas leaks.

More: Reuters

DOE Approves Sabine Pass LNG Export Expansion Plan

The Department of Energy on Friday approved Cheniere Energy’s plan to expand its Sabine Pass liquefied natural gas terminal in Louisiana to export LNG to countries that do not have free trade agreements with the U.S. Cheniere already has four production facilities nearing completion at the terminal. The approval authorizes it to build two more.

The government’s approval came two days after the Federal Energy Regulatory Commission declined a request by the Sierra Club to reconsider its approval of the expansion plans.

The development of new domestic gas fields has transformed the nation’s energy outlook, allowing the industry to promote exports where a decade ago it had been planning to increase imports of LNG to buttress U.S. supplies. The Sabine Pass terminal will be the first large-scale plant in decades to ship LNG from the continental U.S.

More: FuelFix

FERC Denies Request to Extend Public Comment Period on Mountain Valley

The Federal Energy Regulatory Commission has turned down a request to expand the public comment session for a proposed natural gas pipeline that would run through central Virginia. Lawmakers and other officials asked for an extension of the comment period, but FERC Chairman Norman Bay declared the session ended.

The 300-mile Mountain Valley pipeline would transport natural gas from Wetzel County, W.Va., to Pittsylvania County, Va.

More: News Leader

NRC Steps up Oversight at Talen’s Susquehanna Site

The Nuclear Regulatory Commission will increase its oversight of Talen Energy’s Susquehanna nuclear station in Pennsylvania after a recent inspection during an emergency drill identified weaknesses with the plant’s response. Talen Energy was formed by the recent spinoff of PPL’s generation assets.

The problem involves the plant’s interpretation of when to start a 15-minute clock for an emergency assessment of a radioactive leak. Plant personnel thought the clock started when it was determined that crews were unable to stop a leak. But NRC rules say the clock starts when a leak is first detected.

“It’s important during an emergency situation that state, county and local officials are provided with information in a timely manner to assess the situation and implement protective actions, if warranted,” NRC Region I Administrator Dan Dorman said in a news release. “While the probability of an event of this magnitude is extremely low, this finding points to a weakness in that area that the company will need to address.”

More: The Morning Call

DOE Study Finds Canadian Oil Sands Give off Increased Greenhouse Gases

A study funded by the U.S. Department of Energy found that petroleum extracted from Canadian oil sands produces 20% more greenhouse gases than conventional crude. The findings are consistent with long-held assumptions about oil sands production, which requires more energy to extract than conventional oil.

The study, conducted by the department’s Argonne National Laboratory, Stanford University and the University of California, noted that oil sands production is expected to double in the next 15 years, and that half of that crude could end up in the United States.

The findings are expected to fuel debate on the Keystone XL Pipeline, which is designed to transport Canadian crude to oil refineries in the Gulf of Mexico region. Final approval of the pipeline has not yet been granted.

More: Wall Street Journal (subscription required)

FERC to Prepare Impact Statement for Port Arthur LNG Project

The Federal Energy Regulatory Commission has issued a notice of intent to draw up an environmental impact statement for the proposed Port Arthur Liquefaction Project in Texas, as well as an associated pipeline project.

Port Arthur LNG, an affiliate of Sempra LNG, and Port Arthur Pipeline, a subsidiary of Sempra US Gas and Power, are planning to construct and operate interrelated LNG terminal and natural gas infrastructure projects along the Sabine-Neches Ship Channel in Jefferson County, Texas.

The Port Arthur Pipeline Project includes 35 miles of pipeline to supply the export terminal. Part of an existing state highway and as many as five existing pipelines will need to be relocated as part of the project.

More: LNG Industry

June 30, 2015June 15, 2023

Dominion CEO: Ignore the Fringes, not the Science

By Rich Heidorn Jr.

WILLIAMSBURG, Va. — Dominion Resources CEO Tom Farrell spoke of the challenges of social media, the promise of utility-scale solar and the dangers of “magical thinking” in remarks to the 20th annual Education Conference of the Mid-Atlantic Conference of Regulatory Utility Commissioners last week.

“Transitioning from more than three decades of public policy centered on the notion of energy scarcity to energy abundance is a very good problem to have, but nevertheless it’s a problem,” Farrell said. Making the transition, he said, will require new gas and electric infrastructure and a rational response to environmental regulations.

“The combined effect of the proposed climate change, air quality, water quality, ash disposal and many other [energy-related] regulations on customer costs and reliability is a great cause for concern … But wishing away regulations we might differ with is not an option,” he said.

“We must avoid magical thinking in the public policy arena — the type of thinking that bypasses the laws of physics, the limits of technology and the realities of human nature in pursuit of ideological goals. Just as we have long recognized that hope is not a business plan, so we must accept that ideology is not an energy policy.”

Farrell said he expects utility-scale solar to be part of the response to the Environmental Protection Agency’s Clean Power Plan. “Although much of the public policy debate and all of the publicity tends to focus on distributed solar, the real story has been the explosive growth in utility–scale solar, by far the most cost-effective … and useful complement to traditional generation,” he said.

Farrell praised Federal Energy Regulatory Commission Chairman Norman Bay’s suggestion earlier in the conference that states create “energy corridors” for siting both electric and gas lines.

Meeting future environmental rules, Farrell said, will require utilities to overcome obstacles from both infrastructure opponents and federal agencies responsible for approving siting of new lines.

“Social media … accelerates the flow of information — and misinformation — on the Web. In the hands of those who oppose new energy infrastructure, social media gone viral can erode industry’s credibility and make our job of communicating facts much harder. But communicate we must. Our industry has not always been on the cutting edge in the use of social media tools. But we’re going to have to learn how to do it and we’re going to have to learn how to respond.”

Farrell said utilities are facing an unusual alliance of “environmental groups who don’t want any fossil fuels used at all” and Tea Party-type activists who “say I’m happy to use gas or electricity, but I don’t want you doing it on my property.”

“When you put those two together that’s a very interesting coalition,” he said. “I think you’re going to see … that grow exponentially over the next five years.”

He expressed frustration with what he said were seemingly contradictory directives from federal agencies, citing the difficulty Dominion has had in winning federal approval for a transmission line across Virginia’s James River. The line is needed because of the loss of coal-fired generation shuttered due to environmental rules. “We still don’t have all the permits and we’ve been working on it for six years,” he said.

“We would do well to acknowledge that energy issues are highly complex, that there are tradeoffs and opportunity costs embedded in every single policy decision made. There is no silver bullet solution that’s going to solve all the problems and do it reliably and inexpensively,” he said. “In essence this means more hard work on energy policy and less attention paid to energy soundbites coming from the fringes on either side.”

June 30, 2015June 15, 2023

Company Briefs

FirstEnergy officials confirmed that the soon-to-be retired R.E. Burger power plant in Eastern Ohio could be the site of an ethane cracker plant if it reaches a deal with two foreign chemical companies. The news came when FirstEnergy Generation President James Lash said the company is moving a machine shop from the Burger site to Canonsburg, Pa.

The cracker plant would convert ethane produced from the Utica and Marcellus Shale formations into material used by plastics and petrochemical manufacturers Marubeni Corp., of Japan, and PTT Global Chemical Public Co., of Thailand.

More: Pittsburgh Business Times

Columbia Pipeline Spending $2.7 Billion on Shale Gas Transport

Columbia Pipeline Group plans to invest $2.7 billion in natural gas transmission projects to transport production from the Marcellus and Utica shale regions in Appalachia to the Gulf Coast.

Columbia’s Mountainer XPress and Gulf XPress will add capacity to deliver 2.7 bcf/d from shale areas in Ohio, Pennsylvania and West Virginia. The Mountaineer XPress project involves 165 miles of new pipeline, while the Gulf XPress project includes upgrades to existing infrastructure between Kentucky and Louisiana.

The Houston-based Columbia is a subsidiary of NiSource.

More: Columbia Pipeline

Sunny Days Mean Less Stink in Detroit Thanks to Bigbelly

Detroit is becoming the latest city to use the solar-powered Bigbelly sidewalk trash compactors.

DTE Energy will install seven of the trash-compacting and recycling units in several Detroit locations as part of its Energize Detroit neighborhood revitalization program. The idea is to eliminate trash overflows, keep insects away and beautify neighborhoods. The solar units will automatically send signals to collection trucks when they are full.

Bigbelly says its units are operating in 47 countries and that Philadelphia has installed about 1,000 of the devices.

More: DTE Energy; Bigbelly

SPS Case Spurned by New Mexico Commission over Detail

The New Mexico Public Regulation Commission has dismissed Southwestern Public Service Co.’s latest rate case filing, which would have increased base rates by $1.4 million in mid-2016.

The commission said SPS did not comply with its new interpretation of a statute involving forecasted test year (FTY) periods, according to a regulatory filing by SPS’s parent, Xcel Energy. SPS said it plans to refile the rate case later this year.

More: Securities and Exchange Commission

Energy Future Holdings Calls off Oncor Auction Plans

Energy Future Holdings, 80% owner of transmission company Oncor, has told a Delaware Bankruptcy Court judge that it is calling off the planned auction of its ownership stake and will go ahead with a reorganization plan.

The Texas energy giant filed for Chapter 11 bankruptcy protection in April 2014, saddled by debt. It announced last year that it was giving up on its original restructuring plan and would auction off its Oncor stake, which is valued at about $19 billion. NextEra Energy and Hunt Consolidated Inc. were identified as likely bidders.

But Energy Future says it will now return to Plan A and reorganize. It plans to emerge from bankruptcy next year.

More: Wall Street Journal (subscription required)

Bill Gates to Double Renewable Energy Stake

Microsoft founder Bill Gates, who says he has already invested an estimated $1 billion in renewable energy companies, plans to double his investment within the next five years.

Gates has concentrated his green investments in energy storage, advanced nuclear and carbon capture technologies.

He said it is time for such companies to push the envelope to develop new methods to bring renewable energy to market. “Power is about reliability,” he said. “We need to get something that works reliably.”

More: Financial Times (subscription required)

Duke Selling off Stake in Integrys Energy Systems

Duke Energy is divesting its stake in a five-year-old rooftop solar joint venture with Integrys Energy Systems.

Duke is selling its 9-MW share of the 32-MW venture to TerraForm Power, of Maryland. TerraForm had already purchased the other 23 MW from Integrys. Together, Duke and Integrys invested about $180 million in a variety of small solar projects. It marked Duke’s first venture into solar.

More: Charlotte Business Journal

NextEra Energy Looking for New Wind Site in North Dakota

NextEra Energy Resources, which in May withdrew an application to build a $250 million wind farm in North Dakota, announced it is looking for sites for a similar plant.

Although the company won’t give details on sites it is considering, a member of the Public Service Commission said the company is not looking far from the location of its first project.

“NextEra has informed us they’re looking at multiple locations and all of those locations are south of where they were looking at before,” Commissioner Brian Kalk said. The first plan was shelved after landowners objected and the Stark County Commission denied the company a conditional use permit.

More: Prairie Business Magazine

June 30, 2015June 15, 2023

Exelon: EPA Plan Will Get Nuclear Issue ‘Half Right’

Joe Dominguez, executive vice president of government and regulatory affairs for Exelon, said the company is not abandoning organized markets but needs them to reflect the cost of carbon emissions for its nuclear fleet to survive.

“The work that we’ve seen from the RTOs — from PJM, even from ERCOT — indicate that with a relatively modest price on carbon we can achieve compliance with the EPA’s [Clean Power] Plan.”

Dominguez said he believes EPA will get the nuclear issue “half right” in the final emissions rule, due this summer.

“My guess is EPA is going to largely ignore the problem and hope that nuclear plants don’t retire,” he said.

But he predicted that EPA will “give substantial incentives for mass-based regional cooperative programs to achieve compliance.”

“And there, I think, nuclear is going to be fully recognized, because in any mass-based program the loss of nuclear units would quite obviously be reflected in an increase in the emissions as fossil fuel takes up the gap left by nuclear. That will self-correct.”

June 30, 2015

Ideas to Reform MISO Out-of-Cycle Process Emerge

By Chris O’Malley

MISO stakeholders have submitted recommendations for refining the out-of-cycle request process in the wake of transmission developer complaints over Entergy’s $187 million transmission upgrade near Lake Charles, La.

MISO approved the OOC request, which Entergy said was necessary to meet the sudden needs of an industrial customer, following a clamor from transmission developers complaining they were denied a chance to compete for the project. (See Entergy Out-of-Cycle Requests Win MISO Board OK.)

Transmission developers, transmission owners and ITC Holdings proposed numerous changes to MISO’s Transmission Planning Business Practices Manual. “The urgency and the need cannot be the result of inadequate planning, or worse, action that attempts to circumvent the robust, stakeholder-driven process” in the MISO Transmission Expansion Plan (MTEP), the TD sector said in comments submitted at a Planning Advisory Committee meeting.

Among the sector’s proposed changes is a requirement that OOC projects involving multiple load additions have “documented customer service requests.” One of the criticisms of the Entergy OOC request was that neither MISO nor stakeholders were privy to details about the Entergy customer or its specific load needs.

Entergy pointed broadly to an industrial renaissance in the Lake Charles region and said that it received unanticipated customer demand for service after the annual MTEP cutoff date. It said it was not permitted to disclose the customer.

The TD sector also proposed to insert language that would require MISO, before submitting a request for stakeholder review, to determine that a project “does not directly or indirectly eliminate the need for a Market Efficiency Project or Multi-Value Project” — projects that are subject to competition.

More Flexible Language

Meanwhile, TOs are seeking to tweak OOC eligibility rules. They proposed language that notes that “it is not possible to predict every event that will lead to the need for OOC treatment” of a baseline reliability project or “other” project. For example, projects may be driven by generation retirements or regulatory mandates, they said.

ITC Holdings, which did not join with the majority of transmission owner comments, also proposed to change the criteria for OOC project designation. ITC said its language change would allow for needs not specifically identified in the existing criteria. “For example, storm damage that necessitates a system change may require OOC review,” ITC said.

Alternatives to OOC

Other changes proposed for the Transmission Planning Business Practices Manual involve stakeholder reviews of OOC requests.

The TD sector complained that MISO moved too fast on Entergy’s Lake Charles request, without adequate feedback from stakeholders.

The sector is seeking at least one sub-regional planning meeting or public Technical Studies Task Force meeting “at which the out-of-cycle project and identified alternatives will be evaluated.” Stakeholders would be able to submit alternatives to an OOC at a following sub-regional or task force meeting.

TOs Assert Rights

At the PAC meeting last week, MISO officials attempted to compare the suggested stakeholder redlines to the BPM manual. Stakeholders offered some additional perspective.

“What we were trying to do is return this BPM language to its fundamental source, which is the transmission owner’s agreement,” said Cynthia Crane, principal regulatory analyst at ITC Holdings.

“And that’s what’s missing in all this dialog, it’s [that] the transmission owners agreement gives transmission owners certain rights” such as to upgrade, modify, alter or replace its facilities, she said. “We have to be really careful in what we are drafting here in order to not violate the TOA,” she added.

Jeff Webb, director of planning at MISO, said “The last thing you want to do is impede the TOs’ [ability to meet their] obligations.”

Suspicion of OOC Requests

But some speaking at the PAC meeting urged MISO to be vigilant about maintaining oversight, given the potential for utilities to misuse the OOC process.

“I can play this game all day where I need to build [a line] because I haven’t put my load in for three years now and I know it’s coming, but I don’t want to go through that competitive process stuff,” said Kip Fox, director of transmission strategy and grid development at American Electric Power, speaking of a hypothetical abuse. “So I’ll just wait until the four-year window closes and then I’ll submit it and all of the sudden it’s a reliability project.”

Fox told MISO: “You have to give us some confidence that those loads are being looked at.”

Webb noted the challenge in obtaining information from a load-serving entity making an OOC request. “What is the load-serving entity able and willing to disclose to defuse this sort of ‘proof issue’ that’s in front of us?”

Load-serving entities often counter that they’re prevented by nondisclosure agreements from revealing specifics about customer expansion plans.

Webb said MISO would review the feedback and return at a future meeting with draft language of its own.

June 30, 2015June 15, 2023

PJM Markets and Reliability Committee Briefs

PJM doesn’t plan to allow generators to make hourly market offers for winter 2015/16, despite a Federal Energy Regulatory Commission order that such flexibility be developed by Nov. 1.

Officials said the RTO cannot accept such offers until it revamps its market system and that the new software cannot be completed by next winter.

In its June 9 ruling, FERC ordered PJM to file Tariff changes allowing market participants to submit day-ahead offers that vary by the hour and update their offers in real time, including in emergency situations, or explain why the changes are unnecessary. The commission said the changes should take effect by Nov. 1 “or as soon as practicable thereafter.” PJM must make a compliance filing informing the commission of its plans by July 10. (See Duke, ODEC Denied ‘Stranded’ Gas Compensation.)

In April, stakeholders approved the creation of the Generator Offer Flexibility Senior Task Force to consider such changes in response to a problem statement by Calpine. Calpine noted that PJM is the only organized market in the country that doesn’t permit generators to vary their offers hourly. (See Bid for Generator Price Flexibility Draws Debate over 10% Adder.)

PJM said it considered proposing an interim solution while it waits for the software changes but bowed to stakeholder sentiment for a single, long-term solution.

The task force held its first meeting June 29.

Monitor: Marginal Benefit Factor Faulty, Inconsistently Applied

The Independent Market Monitor is recommending a broader look at concerns that PJM is buying too much fast-responding “RegD” resources in the regulation market. The Monitor said Thursday that stakeholders should revisit the marginal benefit factor that defines the substitutability between “RegA” and RegD megawatts.

“PJM’s current marginal benefit factor function is, at least in some hours, overvaluing RegD as a substitute for RegA in the optimization,” said Howard Haas of Monitoring Analytics. The misalignment also means RegD resources are being incorrectly compensated — sometimes being paid too little, and sometimes too much, Haas said. (See PJM Market Monitor: Faulty Marginal Benefit Factor Harming Regulation.)

The Monitor proposed a problem statement and issue charge that will be considered at the MRC’s July 23 meeting.

PJM introduced its own problem statement on the regulation issue at the April Operating Committee meeting, but it has not yet been brought to a vote. Under times of system stress, PJM said, it has observed issues with regulation performance when the proportion of megawatts from RegD resources is greater than 42%. (See “Too Much of a Good Thing? PJM Concerned Fast Response Regulation Crowding out Traditional Resources,” PJM Operating Committee Briefs.)

A PJM official told the MRC that the RTO is currently performing a study on the issue, which will take eight weeks to complete.

Changes Would Allow Earlier Replacement Transactions

The committee will be asked to vote at its July 23 meeting on manual changes that 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.

Such replacements would be permitted when the owner of the replaced resource could show the expected final physical position of the resource at the time of the request.

Existing generators could engage in such transactions if they are being deactivated, while new generators could replace themselves if their project is cancelled or delayed. Demand response or energy efficiency resources could be replaced due to the permanent departure of their loads.

Resources replaced would not be able to be recommitted for the delivery year.

PJM Law Proposes Cleaning up Language in Governing Documents

The PJM Law Department proposed an initiative to clean up language in the RTO’s governing documents that is “ambiguous, incorrect or requires clarification.”

The project would entail reviewing the Tariff, Operating Agreement and Reliability Assurance Agreement related to topics including offer caps and prices, demand resources and the capacity market.

PJM’s proposed problem statement and issue charge would assign the task to the Market Implementation Committee, separating it from the effort already underway involving the Tariff Harmonization Senior Task Force. The task force was formed in December to identify discrepancies in provisions regarding definitions, indemnification, limitation of liability and alternative dispute resolution procedures in the same governing documents. (See Task Force Proposed to Resolve Inconsistencies in PJM Governing Documents.)

Ed Tatum of Old Dominion Electric Cooperative suggested that PJM consider unifying the efforts, saying ODEC wanted to participate but had limited resources. “Words do matter,” he said. “Anytime we do something like this, it’s a big deal.”

“I didn’t think what we were trying to do here really fit” the task force’s charter, responded PJM attorney Jacqui Hugee, who added the charter could be changed.

The task force plans to bring its first batch of changes to the next MRC meeting for a vote, along with a second batch for first reading.

Changes to Manuals 03, 3A, 19 Endorsed

Members endorsed the following manual changes:

Manual 19: Load Forecasting and Analysis. Makes changes to residential measurement and verification rules. Provides a solution for the issue that some electric distribution companies (EDCs) are prohibited from sharing personally identifiable information about residential customers participating in demand response programs. EDCs may use unique ID numbers instead through May 31, 2016.
Manual 03: Transmission Operations. Requires a separation between emergency and load dump ratings. In the event they are the same, the emergency rating submitted by the transmission owner shall be, at a minimum, 3% lower than the submitted Load Dump rating. If this change results in a normal rating that is higher than the long-term emergency rating, the TO shall, at a minimum, make the normal rating equal to the LTE rating.
Manual 3A: Energy Management System Model Updates and Quality Assurance. Continues effort to streamline and update sections pertaining to model updates. Most significant change is new section added on sub-transmission model submission requirements. TERM Appendix A reworked to more clearly outline business rules and tool interaction.

— Suzanne Herel

June 30, 2015June 15, 2023

ODEC Seeks Last-Ditch Vote on Deadlocked FTR/ARR Issue

By Suzanne Herel

WILMINGTON, Del. — Old Dominion Electric Cooperative introduced a last-ditch effort to reach consensus on a redesign of the financial transmission rights and auction revenue rights processes Thursday, seeking a vote on a proposal combining recommendations from PJM and the Independent Market Monitor.

ODEC’s Steve Lieberman introduced the proposal to the Markets and Reliability Committee, prompted by a discussion at the May MRC meeting over whether the deadlocked FTR/ARR Senior Task Force should be disbanded. (See Move to Disband FTR Task Force Splits PJM Members.)

The task force was established last spring to address concerns that FTR funding was falling short of target allocations. Although it was unable to reach consensus on rule changes, the FTR funding shortfall has evaporated as PJM has become more conservative in its modeling of ARRs and FTRs. For the 2014/15 planning year, which ended May 31, 2015, FTR funding had a surplus of more than $130 million.

As a result, however, Lieberman said, Stage 1B and Stage 2 ARR allocations have been “nearly eliminated.”

“In ODEC’s mind, this highlights the need for additional transmission development.”

His proposal, which will be brought to a vote at the July MRC meeting, incorporates three elements, which PJM had presented to the task force as package 22.

The first, drawn from a PJM staff proposal regarding the Stage 1A 10-year process, would escalate current ARR results using a zonal load forecast growth rate of +1.5%.

The other two elements were proposed by the Monitor and supported by PJM. It would change the method of reporting the monthly payout ratio so that any negative target allocations are included as revenue, slightly increasing the reported payout ratio.

It would also treat each FTR individually, eliminating the netting of positively and negatively valued FTR positions in a portfolio prior to determining positively valued FTR payout ratios.

Prospects Cloudy

Although the odds against the package winning two-thirds support in a sector-weighted MRC vote may be steep — none of the 12 packages brought to votes at the task force won even a simple majority vote — ODEC did receive some support Thursday.

Market Monitor Joe Bowring said he supported the proposal but said it was only a start in solving the issue.

PJM also endorsed the plan. “PJM would be supportive of moving forward with this particular package,” said Stu Bresler, vice president of market operations.

Carl Johnson, representing the PJM Public Power Coalition, agreed. “This is the best way to move forward. As a load-serving entity, this is something we can support,” he said.

But the proposal had its detractors.

DC Energy’s Bruce Bleiweis, who served on the task force, suggested ODEC eliminate the netting proposal in order to garner wider support. And, he said, “At some point in time, stakeholders and PJM need to agree that we just didn’t come to a solution for the problem we were facing.”

Consultant Roy Shanker agreed with Bleiweis that the “netting” proposal did not increase ARRs.

Shanker also accused ODEC of “cherry picking” from proposals made to the task force. “We’re hearing three-line summaries of things people spent months on,” he said.

“There was no attempt at cherry picking,” Lieberman responded. “It’s the proposal that received the greatest support” at the task force.

Unilateral Filing?

In a June 2 filing with the Federal Energy Regulatory Commission, PJM suggested it may make a unilateral Section 206 filing to break the deadlock. PJM said the shift of revenues from ARR holders to FTR holders “is less equitable and desirable than it would prefer.” (See FERC Denies Rehearing on PJM FTR Funding.)

June 30, 2015June 15, 2023

PJM Considering Release of Uplift, Outage Data

By Rich Heidorn Jr.

WILMINGTON, Del. — PJM is proposing to relax confidentiality rules regarding uplift payments and generator outages, saying they are inhibiting stakeholder discussions.

The RTO on Thursday presented the Markets and Reliability Committee a problem statement and proposed changes to section 3.5 of PJM Manual 33.

PJM said the proposed changes were prompted by requests from stakeholders for more granular data, particularly following severe system events such as weather disruptions.

The existing rules, which were prompted by the Federal Energy Regulatory Commission’s Order 719, have “no strict definition” of what information is confidential and do not consider the age of the information — meaning data considered confidential remains that way even after the reason for nondisclosure may have passed, PJM said.

The manual currently allows release of aggregate market data only if it includes more than three market participants’ data and the aggregation is for an area no smaller than a PJM transmission zone. The rules also prohibit PJM from disclosing some data even if it has been released publicly elsewhere, such as the nuclear plant outages the Nuclear Regulatory Commission posts on its website.

As a result, said PJM’s Tom Zadlo, the RTO is unable to be specific about conditions surrounding weather events, closed-loop interfaces and transmission planning.

Uplift Recipients

The Independent Market Monitor called for changes to the confidentiality rules in February 2014, when it disclosed that 10 generating units had received $335 million in uplift payments in 2013, 38% of the RTO’s total for the year. The Monitor contends all uplift payments should be public information, saying that identifying the causes of uplift and the generators receiving payments would allow competition to reduce those costs.

PJM said then that it would be unable to disclose the names of the units in question without a FERC order. (See PJM Won’t Name Uplift Recipients.) But in its proposed manual changes, PJM altered its position, saying that generator-specific information regarding uplift payments would not be considered confidential and that the RTO may disseminate the information daily.

Other Changes

The changes also would allow PJM to release information on generation outages once they have concluded, “if PJM deems them to be relevant.” The RTO said it would release such data only when related to an event on the grid, such as severe weather or a transmission system event.

PJM noted that while generation outage data has been considered confidential by the RTO it publishes transmission outages on its OASIS system.

The RTO also would be able to disclose demand response supplies in small areas, such as a group of zip codes, information it said is important to understanding the impact of weather events and closed-loop interfaces. Specific offers or suppliers would not be released.

The identities of generators that cleared in capacity market auctions — though not their offers — also would be disclosed.

Data that is already in the public domain from other sources would no longer be considered confidential.

Market Monitor Joe Bowring said he may ask PJM to consider amendments to the scope of the problem statement, which is expected to be brought to a vote at the July MRC meeting.

Stakeholder Concerns

Jason Barker of Exelon expressed misgivings over the release of information on generators receiving uplift payments, saying it would give competitors “information about what unit costs are.”

John Citrolo of Public Service Electric and Gas also expressed concern, saying release of uplift and outage information could “send the wrong message” to investors of publicly traded companies and interfere with established communication protocols with their organized labor.

June 30, 2015June 15, 2023

PJM Moving on Day-Ahead Schedule Changes

By Rich Heidorn Jr.

WILMINGTON, Del. — PJM officials said last week they intend to move up the day-ahead energy market schedule despite a lack of consensus among stakeholders.

RTO officials said they believe the change is necessary as a result of the Federal Energy Regulatory Commission’s April order moving the timely nomination cycle deadline for gas to 2 p.m. ET from 12:30 p.m. and adding a third intraday nomination cycle.

The order required grid operators to adjust the posting of their day-ahead energy market and reliability unit commitment processes to a time “sufficiently in advance” of the timely and evening gas nomination cycles to allow generators to obtain gas (or to show cause why such changes are not necessary). Compliance filings are due July 23. (See FERC Approves Final Rule on Gas-Electric Coordination.)

Adrien Ford, director of market evolution, said PJM officials determined that they must change the energy market deadlines to comply with the order.

PJM’s filing will propose moving the deadline for submitting day-ahead offers up 90 minutes to 10:30 a.m. ET from noon. The RTO said it will post day-ahead results by 1:30 p.m., up from the current 4 p.m., as it reduces its clearing time to three hours from four.

The rebid window for the reliability assessment and commitment (RAC) run will be open from 1:30 to 2:15 p.m., up from the current 4 to 6 p.m. (Day-ahead commitments are based on demand bids from load-serving entities; the RAC run adds resources PJM believes may be needed based on PJM’s load forecast.)

In a poll of 51 stakeholders, none of the five suggested day-ahead clearing windows received a supermajority.

Slightly more than half of voters selected as their first choice a clearing window of 11 a.m. to 2 p.m., which PJM said would be too late to comply with the order. A clearing window of 10:15 a.m. to 1:15 p.m. was the first choice of 29%.

PJM said the window it proposed “received the highest overall support.” Although it was the first choice of only 8%, 31% picked it second and 59% made it their third choice.

Ford said stakeholders expressed a variety of opinions on how much time they needed between the posting of energy market awards and the gas nomination deadlines. “There was one stakeholder that needed 10 minutes. We had other members who said they needed an hour. There were others who didn’t think any of these [proposed windows] were sufficient,” Ford said. “Based on what I heard, 30 minutes was a way to meet” the FERC compliance requirement.

Stakeholder Reaction

Consultant Bob O’Connell said the changes increase risk premiums because generators will be basing offers into PJM’s markets on gas transactions executed during periods in which there is less price transparency. “You’re imposing higher costs on customers,” he said, adding that PJM should set a goal of clearing the day-ahead market in two hours or less.

John Citrolo of Public Service Electric and Gas said his company, which owns gas generation, would prefer a somewhat later start than proposed by PJM. But he added, “If gas traders get to their desks by 7 a.m. and show me some liquid prices by 9 a.m.,” the industry will adapt.

David “Scarp” Scarpignato of Calpine said his company supports PJM’s proposal, calling it “critical” to the company, whose fleet is virtually all gas-fired.

Generators with firm transportation can use second intraday nomination (ID 2) to bump those without firm transport who bought gas in ID 1. ID 3 is not bumpable.

As a result, if generators selected on the reliability run aren’t able to get their gas nominations in time for ID 2 at 3:30 pm., he said, “We’re not going to get gas.”

“Under [Capacity Performance], PJM has told generators to secure firm gas transport,” he added. “What’s the point of getting firm gas transport if we don’t get committed in time to use it?”

“We think we can get most RAC run commitments out before ID 2,” said Stu Bresler, PJM vice president of market operations.

Citrolo noted that PJM clears about 94% of its megawatts in the day-ahead market, urging, “Don’t turn things upside down for the other 6%.”

Scarp countered that on some days, the RAC run could provide as much as 12,000 MW. “It would be absolutely critical for reliability,” he said.

“We’ve been managing that later rebid window with one less nomination cycle for years,” responded Citrolo.

“And we’ve had a lot of units that can’t get gas,” interjected Mike Kormos, PJM executive vice president of operations. “We’ve been managing, but not that well.”

June 30, 2015

Monitor at Odds with PJM, Marketer over FTR Forfeiture Rule

By Rich Heidorn Jr.

PJM’s Independent Market Monitor told the Federal Energy Regulatory Commission last week that proposals by the RTO and a marketer to change the financial transmission rights (FTR) forfeiture rule would weaken protections against market manipulation.

The Monitor leveled the criticism in comments filed last week in the Section 206 case FERC ordered last year regarding the RTO’s treatment of virtual transactions (EL14-37).

The Monitor said PJM’s proposal to use a load- or generation-weighted reference bus rather than the largest impact bus would “functionally eliminate” the forfeiture rule under the current, non-portfolio approach to evaluating impacts of transactions on congestion.

In September, FERC ordered the Section 206 proceeding to determine whether PJM is improperly treating up-to-congestion transactions differently than incremental offers (INCs) and decrement bids (DECs). While INCs and DECs are charged uplift and subject to the FTR forfeiture rule, UTCs are exempt from both.

Ruling by October?

The Monitor’s criticism was in response to some of the almost two dozen comments filed in late May following a Jan. 7 technical conference on the issue.

In opening the Section 206 docket last year, the commission said it would rule within five months after it receives comments following the technical conference. That would put FERC on schedule for a ruling by the end of October. (See FERC Issues Request for Comments in UTC Uplift Docket; Ruling by October?)

The Monitor’s reply, filed June 23, was also critical of a proposal by EDF Trading to replace the forfeiture rule with individual enforcement actions.

“An enforcement action approach, relative to a rule-based approach, is inefficient, non-transparent and of limited value as a deterrent to market manipulation,” the Monitor said. “Such a rule is unclear and effectively unenforceable, which may be the point.”

The Monitor added that PJM’s current rule not subjecting UTCs to forfeitures “ignores [the] laws of physics.”

“As the power flows from the UTC source to the UTC sink, it flows across constraints. As a result, the net flow from a UTC should be treated the same as an INC when the UTC net flow is an injection and the same as a DEC when the UTC net flow is a withdrawal, under the FTR forfeiture rule.”

Uplift Task Force to Resume

FERC’s ruling in the 206 case may result in the application of uplift charges to UTCs, an issue that has split PJM stakeholders. UTC trading volumes collapsed after Sept. 8, the refund-effective date set by FERC for any uplift assessments.

PJM told the Markets and Reliability Committee on Thursday that the Energy Market Uplift Senior Task Force (EMUSTF) will resume regular meetings in August or September.

Stakeholders had asked to suspend the task force’s efforts on uplift cost allocation pending FERC action on PJM’s Capacity Performance proposal. FERC largely approved the proposal June 9.

Until last week — when it met to discuss the results of the backcast analysis on several cost allocation proposals — the task force had not held a meeting since April.

Also last week, PJM filed a proposed revision on how it pays generators for lost opportunity costs in the day-ahead and real-time markets (ER15-1966). The MRC approved the proposal, which came out of the task force meetings, in April. (See PJM Members Tighten Lost Opportunity Cost Rules; Tech-Specific Eligibility Retained.)