PJM is considering ways to simplify the sharing of real-time generator data to improve situational awareness and help transmission operators respond more quickly in emergencies.
AEP’s Dana Horton urged the Markets and Reliability Committee Thursday to consider changing the current rules on data access, which he said are cumbersome and time consuming.
Horton said transmission operators would “like to be able to see real-time megawatt hour output from all generators in the PJM footprint, like PJM control operations folks do. They’re dealing with a lot of transmission overload issues. If they could see more output data, for more of the region that impacts their area, they are better able to give feedback.”
Horton said the current procedure for obtaining data access, spelled out in Manual 14D, “looks like it was written in the 1950s. It refers to making copies in triplicate.”
State Estimator (Source: ETAP)
Phil Hoffer, an AEP transmission operations manager, said the data would be used as an input to AEP’s state estimator. “Some units may be outside of our control area but have significant impact on our operations,” Hoffer explained.
PJM officials said the RTO supports the effort. “We should be as transparent as we can,” said Executive Vice President for Operations Mike Kormos.
CEO Terry Boston noted that PJM found other transmission operators’ state estimators helpful during the September heat wave, particularly for understanding conditions on lower voltage systems.
PJM Market Monitor Joe Bowring said he would support streamlining the sharing rules if it were done in a way to preserve confidential information. Existing confidentiality agreements and codes of conduct should satisfy any confidentiality concerns, AEP said.
The MRC will be asked to vote on AEP’s issue charge and problem statement at its next meeting. If approved as is, the issue would be assigned to the Operating Committee.
The Markets and Reliability and Members committees approved the following measures with little or no discussion last week:
Markets and Reliability Committee
Changes to Manual 14A: Generation and Transmission Interconnection Process, which updated Attachments F & G. These attachments list wind turbine models that do not need to be reviewed by PJM prior to submission of system impact and generation interconnection feasibility studies. Units listed reflect those PJM has modeled in the past.
Revisions to PJM’s Tariff and Operating Agreement to update the list of agreements and transmission service transactions to which PJM Settlement, Inc. is not a part.
Operating Agreement and Tariff revisions in preparation for eSuite application name changes. These revisions include changing eSchedule and Enhanced Energy Schedule (EES) to InSchedule and ExSchedule, respectively, in the documents. This is part of a larger refresh of eSuite tools, which will occur in stages through the end of the year. (See PJM Updating eSuite Apps.)
Updates to the Regional Transmission and Energy Scheduling Practices for the deployment of ExSchedule. The changes remove ramp reservation and tag timing requirements based on schedule duration. These changes were requested in part due to the new Coordinated Transaction Scheduling (CTS) between PJM and NYISO, which aims to reduce uneconomic flows between the RTOs. (See NYISO Scheduling Product Wins FERC OK.)
Changes to accelerate the schedule of the triennial review of the Cost of New Entry (CONE) by two months. The change, which was also approved by the Members Committee, will move the deadline for staff recommendations to May 15 from July 15 and the projected FERC filing to Oct. 1 from Dec. 1. The CONE review will be conducted every four years beginning with the 2018/2019 Delivery Year.
Members Committee
Tariff revisions associated with CTS and export transactions. The key change is the addition of a provision stating that export transaction screening will not apply to emergency transactions between PJM and neighboring balancing authorities.
Members reacted warily Thursday to PJM’s proposal to develop a generic transition mechanism that would hold capacity providers harmless for future rule changes.
PJM’s Adrien Ford told the Markets and Reliability Committee that the proposal was prompted by the transition mechanism approved by members to protect generators whose installed capacity ratings are reduced by seasonal verification tests. (See Transition Period OKd for Seasonal Verification Rules.)
Bruce Campbell, of demand response provider EnergyConnect, said the proposed solution, based on the Manual 21 fix for generators, may not provide protection for DR.
“This mechanism is really impractical” because it assumes the impact of the changes can be predicted, Campbell said. “We often don’t know what the impact of the changes will be.”
Susan Bruce, of the PJM Industrial Customer Coalition, said she prefers “stability” in capacity market rules. “It might make rule changes too easy to contemplate,” she said.
Exelon’s Jason Barker said his company had “reservations about a `one size fits all’ solution.”
Barker said “it would certainly be helpful to have a default” transition mechanism. But he said it should be spelled out in manuals and not the Tariff or Operating Agreement, where changes would require Federal Energy Regulatory Commission approval.
Katie Guerry, of DR provider EnerNOC, agreed, suggesting the mechanism not be a “defined solution but a set of parameters that must be abided by.”
Ford said PJM officials attempted to address DR in drafting the problem statement. “We wanted to make sure it works for all types of capacity resources,” she said.
Financial Transmission Rights holders asked PJM and Market Monitor Joe Bowring last week to take action to address the continuing shortfall in FTR funding. They received sympathy but no commitments.
In June, the Federal Energy Regulatory Commission rejected a complaint (EL13-47) by FirstEnergy Solutions Corp. that sought to bill all transmission users to make up the shortfalls. While PJM largely supported FirstEnergy’s proposed solution, the Monitor rejected it as “simplistic” and unfair to load.
The commission urged PJM and its stakeholders to reach a consensus solution and to work with its neighbors to reduce congestion on the RTO’s borders. In August, the commission granted rehearing in the case, keeping the docket open but offering no timetable for further action.
$1.1 Billion
In the interim, market participants say, the problem has only gotten worse. Cumulative shortfalls have grown to more than $1.1 billion (see chart). DC Energy’s Bruce Bleiweis told the Members Committee Thursday that March “could be the worst ever.”
“It’s a problem that hasn’t gone away,” said Bleiweis. “We’re still looking for action.”
PJM introduced FTRs in 1999, intending them to provide a financial hedge against the costs of day-ahead transmission congestion.
The value of an FTR is based upon the difference between the day-ahead congestion price between a specific source and sink. The quantity of FTRs to be auctioned is supposed to be limited by transmission capacity.
But a PJM stakeholder report found that revenues were falling short because pre-auction modeling failed to capture some transmission outages and deratings. The modeling also could not account for market-to-market flowgates added in the middle of a planning period.
Consensus Elusive
Since the report, PJM officials have worked with MISO to reduce congestion resulting from cross-border flows.
Last spring, stakeholders also approved two modeling changes recommended by the Financial Transmission Rights Task Force that were expected to provide modest improvements. But members were unable to reach consensus on others, including several proposed by the Monitor. (See MIC Rejects Change to FTR Long-Term Auction Modeling.) The task force was disbanded in December.
With no solutions coming from the stakeholder process and no action from FERC, Goldman Sachs’ J. Aron & Co. seized upon PJM’s ad hoc creation of a pricing interface in the ATSI region during the Sept. 10-11 heat wave. PJM’s action, intended to make demand response set prices in the area, exacerbated underfunding by $23 million over the two days, J. Aron said in a filing in the FirstEnergy docket in December.
Top Binding Constraints in FTR Auctions and ARR Allocations (Source: State of the Market 2013, fig. 13-1)
FTR holders found a new opportunity to bring the issue up when Bowring gave members a presentation on the 2013 State of the Market report, which also criticized the creation of such interfaces.
Harry Singh, of Goldman Sachs, said market participants used to be able to buy 1.2 or 1.3 FTRs for a path they were looking to hedge, but that the technique no longer works because the level of underfunding varies significantly from day to day. On Feb. 14, for example, the funding was only 30%; on Sept. 10 and 11 it approached zero.
In 2010, load serving entities converted almost 63% of their Auction Revenue Rights (ARRs) to FTRs, Singh said. In 2013, only 31% did so. “That tells you people think it doesn’t work as a hedge,” Singh said. Instead, he said, the market has become a way to speculate on uplift and the level of underfunding.
Sympathy, No Commitments
Bowring and PJM CEO Terry Boston acknowledged the problem but were noncommittal about pursuing solutions.
“I’m almost certain the stakeholder process is not going to come to a resolution on this issue,” Boston said. “But we need to keep it on the table.”
The State of the Market report declared the FTR market performance competitive. But it said the market design was flawed because it “incorporates widespread cross subsidies which are not consistent with an efficient market design and over sells FTRs.”
The Monitor noted that the market has responded to the shortfalls by reducing bid prices and increasing bid volumes.
Clearing prices for FTR obligations averaged $0.30/MW in planning year 2013/14, down from $0.71/MW in 2010-11. FTR obligation sell offers dropped to $0.05/MW down from $0.22/MW over the same period.
The report reiterates eight recommendations Bowring made in an April 2013 filing in response to the FirstEnergy complaint.
Bowring said the eight recommendations could increase the FTR payout ratio to almost 96% from the current rate in the mid-70s. The recommendations included a reduction in the allocation of ARRs, the elimination of portfolio “netting” and using probabilistic analysis to improve transmission outage modeling.
In response to a question from Bleiweis, Bowring said he had considered making a Section 206 filing to win FERC approval for his proposed changes. “It’s really a question of timing,” Bowring said, adding that he’d like “to see if others will join us” in support.
PJM’s day-ahead prices for last Thursday turned out to be far more modest than they initially appeared.
The RTO reposted the day-ahead results for March 27 after officials identified an error in the input data used to clear the market. A value of 350 MW was used for the West Interface instead of 3,500 MW for hours 8 through 23, causing incorrect prices and quantities in the day-ahead market solution.
A glum Stu Bresler, vice president of market operations, informed stakeholders of the error at the end of Thursday’s Members Committee meeting. In reposting the results, Bresler said PJM was invoking a provision put in the Tariff “with the hope that we’d never have to use it.”
The changes reduced prices by as much as $37/MWh, with the biggest changes seen in the AECO, BGE, JCPL, METED, PECO, PPL and PSEG zones. In the PPL zone, for example, the LMP for hour 20 — originally posted at $89.41 — was reduced to $52.16.
Bresler said yesterday that the error resulted in higher day-ahead dispatch orders for some generators east of the West Interface and lower orders for those to the west, but that the actual dispatch of the units in real time was unaffected.
Bresler said the apparent constraint at the West Interface “didn’t bind that hard, so it wasn’t enough to raise a red flag” before the day-ahead results were initially posted.
He said officials are investigating whether they can add an automated check to prevent such errors in the future. “We certainly don’t want the market to think this is going to be a regular occurrence,” he said.
The Federal Energy Regulatory Commission has scheduled a hearing over how much Duke Energy will pay to resolve its obligations for transmission expansion projects in MISO after settlement talks collapsed.
Administrative Law Judge Philip C. Baten ordered a prehearing conference for April 1, in preparation for a scheduled Oct. 21 hearing in the case (ER12-91), which resulted from the move by Duke Energy’s Ohio and Kentucky utilities from MISO to PJM in May 2010.
In September, FERC rejected a settlement by Duke’s affiliates, ruling that the agreement unfairly imposed transition costs on transmission customers who were not party to the agreement. (See FERC Rejects Settlements over ATSI, Duke Moves to PJM.)
Baten ordered the case to hearing after the parties indicated at a settlement conference March 10 that they were at an impasse.
WASHINGTON — Tony Clark, the junior member of the Federal Energy Regulatory Commission, rarely says much at the commission’s monthly meetings. On Thursday, however, he became the latest of his colleagues to criticize former Chairman Jon Wellinghoff’s crusade to bring attention to physical threats to the grid.
Clark made a pointed reference to Wellinghoff in praising acting Chair Cheryl LaFleur for leading the commission to issue a rule March 7 directing the North American Electric Reliability Corp. to develop measures to protect the grid from physical threats.
The order was prompted by concerns raised by the April 2013 attack on Pacific Gas and Electric’s Metcalf substation.
Former FERC Chair Jon Wellinghoff
“As all of you who work with FERC know, the chairman at any given time shoulders the responsibility of directing the drafting of orders and deciding what will be circulated to his or her colleagues for approval,” Clark said in a prepared statement. “In all honesty, something along these lines could have and perhaps should have been done months, if not several years ago …”
Wellinghoff, who was chairman from 2009 until December, has been widely quoted in news accounts since leaving the commission in a campaign to raise awareness of the threat of sabotage. He has called the Metcalf attack “the most significant incident of domestic terrorism involving the grid” to date.
Wellinghoff, now a partner at law firm Stoel Rives LLP in San Francisco, did not respond to a request for comment last week.
Norris, Moeller Criticism
At the commission’s February meeting, Commissioners John Norris and Philip Moeller warned that Wellinghoff’s public statements, which were featured in articles in TheWall Street Journal and several California newspapers in February, could result in copycat attacks. Norris also warned against overreacting to the threats, saying it could lead to wasteful spending. (See FERC, NERC: Don’t Overreact to Sabotage Threat.)
LaFleur did not criticize Wellinghoff’s actions but said she agreed with her colleagues that “the resilience of the grid needs to be viewed broadly.”
Critical Substations
The Journal’s Feb. 5 article also reported Wellinghoff saying that a FERC analysis found that “if a surprisingly small number of U.S. substations were knocked out at once, that could destabilize the system enough to cause a blackout that could encompass most of the U.S.”
On March 13, the Journal published a second article reporting details from a confidential FERC analysis — apparently the same one Wellinghoff had referred to in February — that concluded the country’s entire grid could be shut down for weeks or months if only nine substations were sabotaged.
The newspaper did not identify the locations of those substations or its source for the study.
The article said that FERC had conducted power flow analyses on the most critical 30 substations among 55,000 substations nationwide. It reportedly concluded that disabling just nine substations — four in the East, three in the West and two in Texas — could send the nation into darkness.
The Journal said it had reviewed a memo prepared by Leonard Tao, FERC’s director of external affairs, that summarized the study’s findings: “Destroy nine interconnection substations and a transformer manufacturer and the entire United States grid would be down for at least 18 months, probably longer,” said the memo.
Wellinghoff also commented for the March 13 article. “There are probably less than 100 critical high voltage substations on our grid in this country that need to be protected from a physical attack,” the Journal quoted Wellinghoff. “It is neither a monumental task, nor is it an inordinate sum of money that would be required to do so.”
Leak of Report Condemned
That article drew harsh condemnation. “Whoever is the source of this leak — and it appears to be someone with a great deal of access to highly sensitive, narrowly distributed FERC documents — is clearly putting our nation at risk,” Sen. Lisa Murkowski (R-Alaska), said in a statement. “If his or her actions are not illegal, they should be.”
LaFleur, in a statement the same day, acknowledged the newspaper had not identified the critical substations but condemned it for publishing “other sensitive information.”
There may be value in discussing steps to keep the grid safe, she said, but “the publication of sensitive material about the grid crosses the line from transparency to irresponsibility, and gives those who would do us harm a roadmap to achieve malicious designs.”
NERC issued a statement saying “Articles like the one in The Wall Street Journal today do nothing to improve security, rather they jeopardize it.”
Clark last week did not criticize the Journal but did “find fault with those people who may possess sensitive or confidential information, and then choose to release it.”
Costly Investments
At least two gunmen were believed to be involved in the attack on PG&E’s Metcalf 500/230 kV substation near San Jose. The shooting caused more than $15 million in damage, idling the substation for nearly a month, but no power interruptions. (See Substation Saboteurs ‘No Amateurs’.)
FERC told NERC March 7 to develop standards within 90 days that require transmission operators to conduct risk assessments to determine what facilities could have a critical impact on grid operations if damaged by saboteurs. The standards will also require operators to evaluate their vulnerabilities and implement security plans to protect the critical equipment. (See FERC Orders Rules on Grid’s Physical Security.)
VA State Police guarding a Dominion substation in Dinwiddie County (Source: WTVR-TV)
PG&E said last month it plans to install opaque walls, advanced camera systems, enhanced lighting and additional alarms at multiple substations as a result of the attack. Although it did not place a cost estimate on the improvements, it said it would likely seek a rate increase to fund them.
Dominion Resources Inc. said last month it plans to spend $300 million to $500 million over the next decade to increase security of its facilities. It would include two levels of perimeter security featuring “anti-climb” fences and key-card access systems for substation yards.
Earlier this month, a TV station in Richmond, Va., reported that state troopers had begun guarding two Dominion substations in Dinwiddie and Hanover counties. Dominion said there have been no threats to any of the company’s facilities.
Natural gas production and demand hit new records in 2013, and futures prices suggest the trend may continue this year, FERC staff said last week in their annual State of the Markets review.
Natural gas spot prices, which had fallen to record lows in 2012, rose across the U.S. last year, encouraging shale gas production and pushing wholesale power prices higher.
Most trading hubs saw gas prices increase 30 to 40%, with the biggest increases in the Northeast, where prices occasionally hit $20 to $30 per MMBtu.
Gas demand increased 2.3% in 2013 to a record 70 Bcfd. Residential and commercial demand was up 16%, largely due to colder than normal weather in the first quarter of the year. Industrial demand increased 1.8% due to growth from mining, manufacturing and petrochemicals.
Demand from electric generation dropped 10% as the rise in gas prices reduced the fuel’s competitiveness. As a result, coal saw a 5% increase in electric generation demand.
Gas prices would have risen further but for an increase in supply. Total U.S. supply, including production and imports, averaged 68 Bcfd, up 1.0%. Production from the Marcellus Shale rose 44%.
The increase in production helped push long-term natural gas futures prices lower, leading industry to continue its investments in gas-fueled manufacturing. More than 90 new gas-consuming industrial projects or expansions began operations in 2013 and almost 220 are expected in 2014.
Power Prices up Despite Drop in Demand
Despite a 0.1% decline in power demand nationally, electricity spot prices rose across the country.
The largest increases were in the Northeast, with higher natural gas costs driving prices at the Mass Hub up 54%, and in the West, where prices at Mid-Columbia rose 66% due to reduced hydroelectric production.
Financial trading volumes for natural gas fell on the Intercontinental Exchange (ICE), while trading volumes for electricity rose.
Electric financial trading volumes on ICE rose 19%, with trades with durations of two months to one year up 44%.
FERC attributed the increase to the Dodd-Frank Act. In October 2012, ICE converted cleared energy swaps to futures to address Dodd-Frank regulations to increase transparency. As a result, many transactions previously conducted bilaterally have moved to exchanges, FERC said.
About 92% of the financial trading for electricity products outside ERCOT took place at RTOs, up from 90% in 2012. PJM trades continued to dominate, accounting for 68% of electricity trading on ICE, up from 63% a year earlier.
Natural gas saw declines in both financial and physical trading volumes, with ICE reporting a 14% decline in financial volumes and physical trading dropping 30%. FERC attributed the drop to “relatively stable” gas prices in 2013, which reduced traders’ profits.
Does NRG Energy know something the rest of the electric industry doesn’t? Some on Wall Street seem to think so.
After a week in which it scooped up more than a half-million retail energy customers from Dominion Resources and won approval for its acquisition of bankrupt Edison Mission Energy, NRG shares hit a 52-week high Friday.
Already the nation’s largest independent power producer, NRG will vault past Southern Co. to become the second-largest generator overall with the addition of Edison Mission’s 8,000 MW.
The Edison Mission purchase will add 5,062 MW to NRG’s 13,445 MW generating portfolio in PJM, giving it about 10% of PJM’s installed capacity, ranking it third behind Exelon Corp. and PPL. It also added 2,421 MW in the California ISO, with smaller amounts in MISO, ERCOT and non-RTO regions.
The purchase of Dominion Resources’ retail electric business, announced March 11, will bring it more than 600,000 customers in Illinois, Maryland, New Jersey, Ohio, Connecticut, New York, Massachusetts and Texas. NRG already has 2 million retail electric customers throughout the country served by its retail providers Reliant, Green Mountain Energy, Energy Plus and NRG Residential Solutions.
NRG expects to close on the acquisition by the end of this month. Neither company has disclosed the value of the deal.
NRG’s acquisitiveness is a stark contrast to the strategies of other large generators such as Dominion, Duke Energy and First Energy, which have announced a shift away from competitive retail markets in favor of regulated operations.
NRG, which has been built from a series of acquisitions and owns no legacy utilities, doesn’t have the option of falling back on a rate base.
Still, at a time when other generators are talking about selling or shuttering assets because of low capacity and energy prices, NRG’s decision to double down is a notable counterargument.
Turning Point?
Are we seeing a turning point in the fortunes of competitive generators?
Yes, say analysts at Credit Suisse, who last Friday raised their rating on Exelon to “outperform” and boosted their price target to $35 from $23. “We believe expectations and fundamentals for competitive power have found a bottom, with the potential for a long awaited recovery to take form over the next 12 months,” the company said.
Exelon shares closed yesterday at $32.93, up $1.57 (5%) over Thursday’s close. (NRG shares closed yesterday at $30.36, pulling back slightly from the 52-week high of $30.93.)
Exelon, which owns the largest generation fleet in PJM, could see its market share shrink if it follows through with threats to close one or more nuclear plants. (See Exelon in Lobbying Push to Save Ill. Nukes.)
PJM energy prices rose 10% last year as natural gas prices jumped 40%. (See State of the Market: PJM Passes, with Provisos)PJM’s efforts to limit the volume of imports and demand response that clears in the capacity market could also boost generators’ fortunes.
But most analysts are still labeling Exelon a sell or hold. So NRG’s bullishness carries with it risks.
The Street.com, which rates NRG a “hold,” said the company’s strong revenue growth and cash flow is offset by weak profit margins and decreases in net income and return on equity.
Goldman Sachs upgraded NRG to “buy” from “neutral” on Thursday, saying the company’s cash flow gives it the flexibility to buy back stock and debt, as well as make additional acquisitions.
NRG History
NRG CEO David Crane (Source: NRG)
NRG is well aware of the risks. Born as an unregulated subsidiary of Minneapolis-based Xcel Energy, it fell into bankruptcy in May 2003 after several years of aggressive growth as a result of falling power prices and a decrease in energy trading following the implosion of Enron.
It emerged from Chapter 11 in December 2003, headed by a new CEO David Crane, who remains in charge today.
In late 2005, NRG purchased Texas Genco, the former generation arm of Reliant Energy, from a group of private equity firms. In 2009, it rebuffed a takeover bid by Exelon shortly after acquiring Reliant’s retail operations.
It added renewable power retailer Green Mountain Energy to its portfolio in 2010.
In 2012, it added GenOn Energy, the offspring of Reliant spinoff RRI Energy and Atlanta-based Mirant Corp., and one of the largest independent power producers in the U.S.
Last August it expanded into demand response with the purchase of Energy Curtailment Specialists.
Retail-Generation Synergies
Julien Dumoulin-Smith, a utility analyst at UBS Securities LLC, said the Dominion purchase makes sense for NRG as a way to find a market for its generation.
“When you are thinking about the retail markets, the reality is, if you are a large player, you want to be backstopped by a large generation portfolio,” he said. In terms of retail energy, NRG “has wanted to expand from its core base in Texas to the Northeast for a while. This achieves that.”
NRG spokeswoman Melissa Hensley suggested that the acquisition was part of a long-term play by the company, which hopes to see more markets open to retail competition.
“This acquisition supports NRG’s strategy of growing its retail footprint,” she said in an interview Friday. “Additionally, NRG strongly believes in competitive markets. We want to ensure customers continue to be served through these markets, and we want to be an example for other markets that hope to open up to competition.”
Although Hensley wouldn’t say how many of those 600,000 new customers are in the PJM territory, she said about 80%, or 480,000, are in the Northeast, with the rest in Texas.
In contrast, Dominion has shifted its strategy to focus on regulated earnings. Since 2006, it has been selling off commodity-based operations, such as oil and gas exploration, and production and merchant generation, to concentrate on regulated businesses.
In January it announced its intent to exit the unregulated retail energy business, which had stalled in the last two years, with its customer count falling to 2.1 million, a 2% drop, since 2010.
It highlighted the challenges of the business in its 10-K filing for 2013, noting that it was competing against incumbent utilities with “the advantage of longstanding relationships with their customers and greater name recognition.”
Dominion will retain its nearly 2.4 million customers served by its regulated utility, Dominion Virginia Power.
Renewables
A bankruptcy judge in Chicago approved the sale of the Edison Mission assets to NRG for $2.6 billion. Edison Mission and subsidiary Midwest Generation filed for bankruptcy protection in December 2012, blaming low power prices, high fuel costs and expensive mandated coal plant retrofits. The deal is expected to close April 1.
The acquisition included 1,700 MW of wind, giving NRG more than 2,900 MW of wind and solar in operation or under construction.
That is one of the important points behind NRG’s acquisition, according to Dumoulin-Smith. “This plays into their desire to consolidate into the renewable sector,” he said. “This is something they really wanted to do.”
The Edison Mission generation assets are spread throughout the U.S., in California, Nebraska, Pennsylvania, Texas, Iowa, New Mexico, Minnesota, Illinois, Wyoming, West Virginia, Oklahoma, Utah and Iowa.
PJM Impact
With the EME acquisition, NRG will have about 18,500 MW of generation in PJM, leapfrogging AEP, Dominion and FirstEnergy in the RTO rankings.
The Edison Mission acquisition will boost NRG’s “economic capacity” market share in PJM from 6.8% to 9.4% during the high demand periods in the summer, according to an analysis the company filed with FERC in seeking approval for the purchase.
In CAISO, its post-merger share will grow to 8.3% from 7.3% during the peak winter periods, according to the analysis.
In MISO — the only other FERC-jurisdictional market in which NRG and EME had overlapping assets — NRG’s market share will increase to about 3.1% of total capacity, from 2.9%.
Market Monitor Seeks Mitigation
PJM’s Market Monitor expressed concern that NRG generation near a transmission constraint on the MISO-PJM seam — the Lanesville 345/138 kV transformer — could exert market power. The Monitor also cited a potential increase in market power in the PJM regulation market.
The Monitor asked the commission to require NRG to make cost-based offers in the regulation market and to continue to offer the same units and quantities historically offered into the regulation and Lanesville energy market.
The commission rejected the Monitor’s request for mitigation, saying that transmission upgrades have eliminated Lanesville as a constraint.
Because the Monitor’s analysis found market power screen failures in the regulation market for only 189 hours of the year (2%), “and many of these hours are non-contiguous and are spread over many time periods, we find there are no competitive concerns,” the commission said.
The Federal Energy Regulatory Commission set a six-month deadline for the natural gas and electric industries to better align their daily schedules, adding urgency to changes already proposed by RTO and pipeline representatives.
In a Notice of Proposed Rulemaking (NOPR), FERC said Thursday it wants to start the natural gas operating day earlier, move the Timely Nomination Cycle later and give natural gas shippers more times per day to react to rapid demand changes.
The FERC proposal (RM14-2) largely parallels a “strawman” proposal by the Natural Gas Council, except for the commission’s call to move the start of the gas day to 4 a.m. Central Time (CT) from the current 9 a.m. CT start. The Council, a group of natural gas suppliers and pipeline operators, rejected an earlier start time, saying it would cause safety and contractual problems.
FERC also issued two other orders aimed at addressing natural gas shortfalls in times of high demand.
“This past winter has highlighted the critical and growing interdependence of natural gas pipelines and electricity markets,” Acting Chairman Cheryl LaFleur said. “Today’s orders take steps to recognize and address that interdependence to optimize the use of our gas and electric networks for the benefit of all customers.”
In February, RTO Insider reported that the Natural Gas Council had tentatively agreed after meetings with officials of PJM and other RTOs to move their nominating schedules to later in the day. PJM officials said they would seek to move the RTO’s day-ahead schedule forward. (See Pipelines, PJM to Align Daily Schedules.)
The strawman proposal would:
Extend the Timely Nomination deadline to 1 p.m. CT (from the current 11:30 a.m.);
Provide two intraday cycles during the business day with firm bumping rights; and
Add a third, evening intraday cycle for early morning gas flow with no bumping rights.
Conflict over Gas Day Start
Current Gas Schedule vs. Natural Gas Council ‘Strawman’ (Source: Natural Gas Council)
Unlike FERC’s proposal, however, the strawman proposal by the Gas Council would retain the 9:00 a.m. CT start of the gas day.
The council said it “thoroughly considered” changes to the start of the gas day, looking at three earlier starts (12 midnight, 3 a.m., 6 a.m. CT) and one later (12 noon CT).
It said nighttime starts “raise significant safety concerns” and could make shipper imbalances more difficult to manage. It also noted that some existing contracts are based on the start of the gas day and that different start times would “have vastly different impacts by region.”
As a result, the Council said its consensus was that the gas day must remain unchanged.
FERC’s NOPR would begin the gas day at 4 a.m. CT, the beginning of the morning electric ramp in the East, and before the morning electric ramp in other regions of the country. The change would ensure that generators in all regions would enter the morning electric peak with new daily gas nominations.
“This should largely eliminate the concern that some gas-fired generators will be unable to run during a substantial part of the morning ramp period, because they have burned through their nominated gas before the start of the next gas day,” the commission said. “… As a consequence, gas-fired generators should be less likely either to incur imbalances on pipelines or inform electric transmission operators that they are unavailable.”
Timely Nomination Deadline
The Gas Council said moving the Timely Nomination deadline to 1 p.m. would give generators a greater opportunity to participate in the timely nomination cycle, during which most pipeline capacity is confirmed. It also would increase the value of firm transportation and reduce forecasting errors, the Council said.
This matches the change FERC proposes.
The tradeoff: a 20% to 30% increase in hours for schedulers and traders. In addition, pipelines and LDCs would have less time to confirm and schedule, and producers and customers would have less time to react.
Intraday Changes
The Council said providing two “bumpable” intraday cycles during business hours would help generators manage intraday variations in load and changes in dispatch orders. This, too, would increase staffing costs and create operational challenges on particularly active days.
The proposed third intraday cycle would have a 9 p.m. deadline, with gas flowing at midnight.
This would reduce the gap between the last scheduling opportunity and the end of the gas day to 12 hours, making it easier for generators to arrange for fuel supplies at the beginning of the electric day and avoid derates during the morning ramp.
The Council said that because of limited liquidity in the evening, this cycle may be primarily used to move gas into or out of storage. It, too, would require increased staffing.
To ensure that schedulers and traders can end their day knowing that their gas will flow, the late cycle would not allow bumping.
The Gas Council said it was eager to reach consensus with FERC and electric industry stakeholders, fearing that the alternative would be “contentious and time consuming with substantial uncertainty as to outcome.”
FERC proposed to move from two to four standard intraday nomination cycles, which would occur at 8 a.m., 10:30 a.m., 4 p.m. and 7 p.m., but is predicated upon a 4 a.m. start to the gas day.
180-Day Deadline
The NOPR provides 180 days for the natural gas and electric industries to reach consensus on standards through the North American Energy Standards Board.
FERC issued a separate order investigating RTO and ISO day-ahead scheduling practices. It also issued a rule to show cause, requiring interstate natural gas pipeline operators to revise their tariffs to allow posting offers to purchase released pipeline capacity.
At Thursday’s FERC meeting, Commissioner John R. Norris applauded efforts to improve coordination between the two industries.
“I recognize that finding solutions is particularly challenging for the natural gas industry which faces a greater share of the burden with respect to necessary changes,” Norris said in a statement. “I support today’s order because I believe a more formal process with a specific timeline for action is needed now to bring together all segments of the gas and electric industries to find solutions to gas-electric issues facing our industry.”
Norris said the orders will ensure the existing pipeline infrastructure is optimized “before investing additional funds in new infrastructure.”
But the Gas Council said additional pipeline capacity was also needed, saying the “central issue of how to expand gas infrastructure, particularly in the Northeast, will not be solved by scheduling issues.”
