Search
December 28, 2024

Posted on

Mexico’s Grid Operator to Explore Participation in EIM

By Robert Mullin

An isolated area of Mexico’s grid already interconnected with California could become the first non-U.S. participant in the Western Energy Imbalance Market.

El Centro Nacional de Control de Energía (CENACE) — Mexico’s grid operator — and CAISO today announced an agreement to explore the benefits of having the Baja California Norte region join the West’s only real-time energy market.

While the region has no transmission connections with Baja California Sur or Mexico’s mainland grid, it boasts two 230-kV links with California through the Imperial Valley and Otay Mesa substations. Those lines, known as Path 45, provide about 800 MW of transfer capacity.

caiso eim cenace
The isolated Baja California Norte region’s only transmission interconnections are to the north – with California. | Mexico Ministry of Energy

“CENACE’s Baja California Norte participation in the Western EIM will enable it to benefit from the savings that a large geographic region can offer,” CAISO CEO Steve Berberich said in a statement.

Baja already hosts natural gas-fired generation built in part to serve California’s market, including Sempra Energy’s 625-MW Termoelèctrica de Mexicali and Intergen’s 1,100-MW La Rosita. Deliveries into Imperial Valley can serve San Diego County via the 500-kV Sunrise Powerlink, which was energized in 2014.

The region also has promising potential for wind energy, which is increasingly valuable to California as the state seeks to balance its solar-heavy portfolio in pursuit of a 50% renewable standard. Sempra’s Energía Sierra Juárez, a 155-MW wind farm completed near the U.S. border last year, operates under a 20-year power purchase agreement with San Diego Gas and Electric.

“Mexico has had a long, productive relationship with the ISO as we coordinate the management of our interconnected electricity grids,” CENACE General Director Eduardo Meraz said. “It is only logical for CENACE to carefully consider Baja California Norte’s participation in the Western EIM, with its promises of lower-cost electricity and increased renewable integration.”

Mexico’s energy policy requires the country to generate 30% of its electricity from hydro and other renewable sources by 2021, a mandate that increases to 35% in 2024.

Legislation enacted in 2014 named CENACE the nationwide grid operator and partially deregulated Mexico’s power sector, allowing for expanded private sector participation. The agency, which manages the nation’s wholesale electricity market, operates more than 33,000 miles of high-voltage transmission.

The recently expanded EIM has four members operating in eight U.S. states: Arizona Public Service, NV Energy, PacifiCorp and Puget Sound Energy. (See Arizona Public Service, Puget Sound Energy Begin Trading in EIM.)

Posted on

Monitor Says FERC Erred in PJM FTR Ruling, Seeks Rehearing

By Rory D. Sweeney

PJM’s Independent Market Monitor asked FERC on Friday to reconsider its “flawed” ruling on PJM’s financial transmission rights market, saying it “contradicts the fundamental purpose of returning congestion revenues to load” (EL16-6-001, ER16-121).

bwj5qlkorwocayk5c6nh_full_bowring-joseph-monitoring-analytics-rto-insider
Bowring, PJM’s IMM | © RTO Insider

“A consistent theme of the Sept. 15th order is the unsupported view that load must provide guaranteed and risk-free funding of FTRs as a hedge against day-ahead congestion, and that this is somehow in the interest of load,” the Monitor wrote in its rehearing request. “This approach, favored by the financial participants who own most FTRs, is not consistent with the reason that FTRs exist and has no basis in market logic.”

The commission’s order rejected PJM’s proposal to reduce Stage 1A infeasible auction revenue rights by increasing its zonal load forecast growth rate, saying the change would result in unnecessary transmission projects because it would rely on outdated source and sink points. The commission also rebuffed PJM on its plan to eliminate the netting of negative ARRs in a portfolio against positive ones.

FERC also ordered PJM to allocate balancing congestion to real-time load. It gave the RTO until Nov. 14 to submit a compliance filing. (See FERC Finds PJM ARR/FTR Market Design Flawed; Rejects Proposed Fix.)

An FTR entitles its holder to credits based on locational price differences in the day-ahead energy market when the transmission grid is congested. FTRs can be purchased or converted from ARRs, which are allocated to network and firm point-to-point customers.

market monitor ferc pjm financial transmission rights
| PJM

The Monitor’s request argues that FERC departed from precedent and contradicted earlier orders in striking balancing congestion from the FTR definition.

“Elimination of the total congestion revenues rule means that load-serving entities will be forced to pay to make up the difference when congestion revenues paid to FTR holders are in excess of the total congestion revenues collected,” the Monitor said. “This requires load to pay total congestion, including day-ahead and balancing, and then pay balancing again when it is negative. This is not consistent with the objective of the FTR/ARR design, which is to return congestion revenues to load.”

The Monitor described FERC’s ruling on portfolio netting as “unexplained” and said it “fails to address extensive arguments and examples that show the portfolio netting rule does result in cross subsidies.” The netting rule should be eliminated, the Monitor argued, because it “provides unjustified subsidies to participants holding FTRs with negative target allocations.”

It also challenged the commission’s determination that the Stage 1A allocation rule is necessary, saying it “avoids addressing the actual problem: the complete disconnect between the allocation of ARRs and actual system usage.” The Monitor said “the entire concept of generation to load paths is archaic, reflecting the contract path approach to physical transmission rights prior to the introduction of market.”

Posted on

Report: Calif. ‘Duck Curve’ Growing Faster than Expected

By Robert Mullin

A new research report indicates that the belly of CAISO’s “duck curve” is deepening more quickly than originally expected, with its effects increasingly spread across the year — and not just on the typical spring day depicted by the graph.

The report from consulting firm ScottMadden also suggests that distributed energy resources such as rooftop solar are contributing only modestly to the decline in net load and ramping rates associated with the widespread adoption of solar energy in California.

california duck curve utility-scale solar
The ScottMadden report contends that growth in distributed energy resources is keeping a lid on total load growth, but has little impact on system load —and, therefore, the deepening of the duck curve. | Scott Madden

“The duck curve is driven by utility-scale solar in California, not distributed resources,” the report says.

The report’s authors contend that understanding the root causes and impact of the curve is necessary for responding appropriately to its effect on grid operations.

“If we are to effectively address renewable integration challenges, it is imperative that we understand and address the actual issues that exist,” the report says. “Solutions for a seasonal, weekend, utility-scale solar issue may well be different than solutions for an everyday, distributed resource issue.”

California’s duck curve first appeared in 2013, the product of CAISO’s effort to forecast the long-term impact of increased renewable penetration on its daily operations.

That forecast demonstrated how the adoption of solar and other renewable resources would steadily undercut the ISO’s “net load,” which represents the portion of load that must be served by dispatchable resources such as gas-fired generation and imports. The net load calculation looks at total load for a given interval and subtracts energy generated by variable renewable resources.

Load Declines not Limited to Spring

The duck-shaped curve illustrates how daytime solar output crowds out the need for dispatchable resources during much of the day. That, in turn, creates the need for the sharp ramping of dispatchable resources as the sun begins to set. Over the long term, that ramp is expected to grow steeper as more solar resources come online and further depress net load as the state seeks to meet a 50% renewable energy mandate.

While CAISO’s original duck curve forecast predicted that minimum net load would fall to about 15,000 MW in 2016, this past spring already saw that figure — represented by the curve’s trough — sink to a low of 13,894 MW, a 31% decline from 2011. (See Solar is the Generation of Choice in California.)

Since 2011, ScottMadden said, CAISO’s daytime minimum net loads have been declining throughout the year, not just during the spring periods characterized by low residential loads coupled with relatively high solar generation. Furthermore, steep ramps are becoming more frequent, with the late-day three-hour ramp exceeding 5,000 MW on 58% of days in 2015, compared with 6% in 2011. Last year’s steepest ramp was 10,091 MW, a 62% increase from four years earlier, the report shows.

And the most significant ramps are occurring in fall and winter, when California’s net loads are at their lowest. In 2015, the 20 steepest ramps occurred in December (10), November (eight) and January (two).

The firm’s analysts also determined that the sharpest ramps consistently occur on weekends, the low point for weekly loads. Weekend ramps average 10% higher than those occurring on weekdays.

Weekends More Prone to Impacts

“These results suggest that weekends are more prone to experience the impacts of the duck curve because of their lower system loads,” the report says. “Conversely, higher system loads on weekdays mitigate the midday decline in net load and the impact of the duck curve.”

Perhaps most important from a system planning perspective, the report attempts to dispel the notion that DER is contributing significantly to the shape of the duck curve.

The authors explain that, while behind-the-meter distributed resources and energy efficiency appear to be offsetting growth in California’s total load, together they have little impact on the shape of the daily curve of system load — or load that must be supplied by system resources.

The authors back this claim by comparing CAISO — where distributed resources are just 3% of utility-scale capacity and do not participate in the wholesale market — with Hawaii, where residential solar represents 9% of generation managed by the state’s largest utility. In California, daytime system load has changed little since 2011, while Hawaii has seen a sharp decline over the same period.

Based on those findings, grid solutions need not “be totally dependent on complex DER management,” the report contends.

“Instead, the operational challenges associated with utility-scale solar present the potential for more targeted utility-scale solutions,” the report says.

Posted on

FERC Chair, Panelists Make Forecasts at OMS Meeting

By Amanda Durish Cook

LEXINGTON, Ky. — FERC Chairman Norman Bay headlined the Organization of MISO States’ annual meeting Thursday, where panelists discussed the grid of the future, the growing role of natural gas and the continuing uncertainty over state and federal regulators’ jurisdictions.

The Grid of the Future

Lorenzo Kristov, principal of market and infrastructure policy at CAISO, said a “one-way power flow with passive customers on the end is on its way out.” In 15 years, he envisions a future in which utilities deliver just 50% of load and the rest is served by local resources.

He imagined buildings with smart technology and microgrids that can detach themselves from the grid when service is interrupted. “It can ‘island’ if it has to, but most of the time it doesn’t want to because it wants to interact with the market,” he said. “This is where bottom-up meets top-down.”

Kristov said a more decentralized system is also more secure against increasingly severe weather and cyberattacks.

Jim Gardner, former chair of the Kentucky Public Service Commission, highlighted income disparity and email hacking, two trends tied to the presidential election, that he said would play a future role in power consumption.

Income disparity in the U.S., Gardner said, will manifest itself in the power industry, with one class wanting “concierge electrical service” while the other class “will barely be able to afford their electricity bills.”

“You’re going to have great disparity in the customers,” he said.

Gardner also predicted more cybersecurity scares, which he said will result in more top-down control of RTOs from the federal government.

Bay, who presided over a question-and-answer session at the annual meeting, hesitated to describe what an RTO would look like 20 years out. “The times I’ve been asked to be a talking head, I’ve been totally wrong,” he joked. However, he said the need for RTOs would persist. “I think there’s always going to be the need for the efficiencies of a large-scale grid. There is always going to be a need for transmission, so the wholesale market will continue to exist,” he said.

Devin Hartman of the public policy research organization R Street Institute said new, high-voltage lines can unlock constrained resources. “It’s important to know that sometimes so-called breakthroughs take years to develop,” he said.

Bill Booth of the Mississippi Public Service Commission asked if it was wise to continue to construct new high-voltage lines if distributed resources continue to grow.

Kristov said a careful, “least regrets” planning process will have to be used when building new transmission. “I suspect we will need a lot less than we would under a central utility structure,” he said.

Hartman said there are “huge question marks” in designing rates for distributed resources such as rooftop solar.

Gardner said the uncertainty around creating a model for distributed resources will likely continue. “The states are going to go in fits and starts. There’s not going to be a uniform movement,” he said. “The West doesn’t even have RTOs.”

Kristov said a rate structure could charge distributed resources based on how much volatility they introduce in the market. Standalone rooftop solar could be charged a higher rate than that with battery storage.

David Carr, counsel for the Mississippi Public Service Commission, said the addition of distributed resources could leave low-income populations behind. Kristov said local governments could pick up the slack through community programs.

Joe Paladino, a senior advisor at the U.S. Department of Energy, said integrated, regional planning processes are needed to manage the convergence of natural gas infrastructure with the power industry.

“This industry is very fragmented. Jurisdictions are going to have to start considering each other,” he said.

The panelists agreed that price disparities across locations will continue with the growth of microgrids. “Unless we had one huge central nuclear reactor transmitting power from the same distance,” Paladino said.

“You do,” Kristov injected playfully. “It’s the sun.”

Growth of Natural Gas

MISO strategy advisor Scott Wright said natural gas’s share of MISO electric generation could climb to 40% by 2025, up from 23% in 2015.

“The short version is we have a lot of gas, it’s going to be around for a long time and even the [U.S. Energy Information Administration] agrees,” said panelist Amy Farrell of the American Petroleum Institute.

Richard Levitan of Levitan & Associates said there are 39 GW of gas-capable generation, 21 pipelines and more than 3 million horsepower of compression in MISO North alone. “This region is blessed with massive storage infrastructure,” he added. “These serve as bellows to operating supply.”

Wright added there are about 140 storage fields in the MISO footprint.

Levitan also said MISO North has comparatively very few hours of non-deliverability attributed to line breaks or other issues. “I think you can say there’s barely a scintilla of vulnerability,” he said.

However, DTE Energy’s Don Stanczak did not agree with the rosy talk about the windfall of supply. He said the existing natural gas system was designed for predictable retail heating loads, but the increase in gas-fired power generation will require hourly withdrawals and injections.

“We do have a lot of natural gas storage in Michigan, but I don’t think it’s properly configured,” he said. “In the polar vortex, we were days away from having to decide if our customers wouldn’t have electricity or they wouldn’t have heat. And you can’t have heat without electricity.”

Wright said future developments in rapid injection and withdrawal could allow gas scheduling for power to become more natural, “like breathing,” and eliminate the panic of “did I schedule?” He said, however, that getting natural gas from the wellhead is often fraught with obstacles. “There’s a lot of rate pancaking and nominations across several pipelines.”

“I think we need to remind ourselves of the environmental opposition to pipelines,” Levitan said. “Just expanding existing pipelines has become a daunting task. The Northeast is littered with failed projects.”

Farrell suggested that FERC could encourage pipelines to offer an expanded set of market products.

“The gas-electric process that took place over the last four years was painful, but we have to open up that dialogue again,” said attorney Kelly Daly of Stinson Leonard Street in D.C.

When Jurisdictions Collide

Ted Thomas, chair of the Arkansas Public Service Commission, who moderated a panel on the increasing entanglement of RTO, state and FERC jurisdiction, said “the bright line appears to be getting fuzzy.”

Ohio Public Utilities Commissioner Howard Petricoff said the Federal Power Act’s “just and reasonable” standard is vague when compared to the legislation such as the Clean Air Act.

“There’s virtually no change in the language in the last 70 years in either the Federal Power Act or the Federal Gas Act,” Petricoff said. “It’s a much different industry than in 1935. … Today, we have independent power producers; we have interstate lines; we have a fairly complex industry. … The transmission, the grid and the resale are much more active.”

Jeff Dennis, of Akin Gump Strauss Hauer & Feld, said behind-the-meter generation and merchant generators’ competition with vertically integrated utilities has complicated jurisdictional questions. “Power [used to] flow one way. Consumers consumed and generators generated.”

Petricoff said the Supreme Court’s Electric Power Supply Association ruling affirming FERC’s right to regulate demand response has not answered the question of whether “1 MWh saved is 1 MWh generated.” (See Court’s Reticence Frustrates Energy Bar.)

Dennis said the FPA lacks the “cooperative federalism” that can be found in other federal laws.

“I think unfortunately the courts are going to continue to have to pick sides. That means we’re going to muddle through on a case-by-case basis.

“I think it’s important for the Supreme Court to know what aim regulators have in mind. That aim is critically important,” Dennis added.

“‘Cooperative federalism’ has different dimensions,” Bay said. “If we share the same objective, we can get so much more done rather than if we’re suing each other.”

Bay suggested state regulators make use of pre-filing meetings with FERC to minimize the “chance of friction.”

“I think my priorities are similar to every other [state] regulator here,” Bay continued. “From my perspective, what we should be doing at FERC is adapting to the change while maintaining reliability and just and reasonable rates.”

American Electric Power’s John Crespo said RTOs are dependent on states and local governments, whose regulation of land use, granting of easements and implementation of environmental rules determine if transmission actually gets built.

Bay said states need jurisdictional wiggle room. “States deserve a lot of latitude in pursuing policies that they think are helpful for their citizens. … The states are great for experimentation. At the federal level, you can observe that state experimentation and make decisions.”

Crespo pointed to MISO’s plan to add a forward capacity auction to serve retail choice loads in Illinois and Michigan. “It’s an interesting potential for cooperation between the states and RTOs.”

Distributed resources and DR have created “prosumers,” consumers who can become producers, Crespo continued. “What you could see is a blending of the wholesale and retail markets, and what will that look like from the FERC standpoint? It could be where you have a deeper encroachment of federal regulation on states’ rights,” he said.  “I’m not so sure if states knew what they were giving up when they joined RTOs.”

Bay said utilities are voluntarily joining RTOs in what he called the “march of markets.”

“Utilities are making the decisions for themselves; FERC isn’t forcing them to. Obviously there are benefits to joining an organized market,” he said.

“The RTOs have been very good at producing the lowest cost megawatt-hour, but there are other valid policy goals,” Dennis said. “My belief is that there should be a way for different models to coexist among states, the RTOs and FERC. There needs to be some cooperation with FERC, but that needs to be a two-way street.”

Bay added that states and FERC will have to work together on cybersecurity efforts, quipping, “Hackers don’t care that FERC has jurisdiction over the Bulk Electric System and states have jurisdiction over distribution.”

Petricoff said energy officials are going to get much more creative in the coming years as “even the fundamentals of power” will be altered. “We’re in a decade of change,” he said.

Posted on

SPP MOPC Rejects Change to Transmission Billing Dispute Procedures

By Tom Kleckner

LITTLE ROCK, Ark. — Bowing to arguments from the Public Power sector, the SPP Markets and Operations Policy Committee on Wednesday rejected a rule change that would have allowed transmission owners to collect interest in billing disputes, even if they lose.

SPP’s current Tariff language allows a transmission customer to pay the amount it is disputing into an escrow account, where it is held until the dispute is settled. The interest earned on that account is then paid to the winning party.

The proposed change would have allowed SPP to pay the disputed amounts to TOs while the dispute is underway, and then collect the disputed funds back from the TOs if the customer won its case. However, the customer would not recover the interest.

Attorney Heather Starnes, representing the Missouri Joint Municipal Electric Utility Commission (MJMEUC), said the Tariff change (RR132) would be unfair to transmission customers and would not incent use of the dispute resolution process. She also challenged forwarding disputed funds to non-jurisdictional entities, questioning SPP’s ability to claw back the funds.

spp mopc
Left to right at the SPP MOPC Meeting: SPP EVP & COO Carl Monroe; MOPC Chair Noman Williams, GridLiance; Heather Starnes, MJMEUC, and Richard Dillon, SPP director of market design. | © RTO Insider

“This is a win-win for the TO,” Starnes said. “It gets the disputed funds, gets to use those funds and earn interest on them, and even if the TO loses the dispute, it has still gotten the use of and interest on those funds for the time period in which the dispute is unresolved.”

The measure was opposed by Flat Ridge 2 Wind Energy, MJMEUC and several other public utilities: the City of Independence, Kansas Electric Power Cooperative, Kansas Power Pool, Municipal Energy Agency of Nebraska and the Oklahoma Municipal Power Authority.

SPP supported the revision, saying the changes would align with the Integrated Marketplace’s transmission-settlement process and be easier for staff to administer.

“Administrative efficiency and/or matching up the marketplace and transmission-billing dispute processes are not sufficient justifications for destroying the independent and balanced dispute process currently in place,” Starnes said in her comments against RR132. “SPP having to manage the escrow accounts created incentive for it to work diligently to get disputes resolved.”

“This seems to me to be a solution in search of a problem,” Midwest Energy’s Bill Dowling said.

SPP is one of two RTOs still using FERC’s pro forma tariff language, meaning any revisions to that language must meet a different burden of proof than normal Tariff revisions, Starnes said.

“SPP would have to have proved that RR132 and its process revisions were equal to or better than the FERC pro forma tariff language,” she said.

It was a surprising turnaround. The proposal had cleared the Regional Tariff Working Group in April with only two abstentions.

Only Oklahoma Gas & Electric opposed the MOPC’s rejection of the revision request. There were three abstentions.

Staff assured members that transmission-revenue funds won’t be commingled with Attachment Z2 funds.

Posted on

MOPC Rejects Z2 Waivers; Task Force Seeks Changes

By Tom Kleckner

LITTLE ROCK, Ark. — SPP stakeholders once again took up the issue of Z2 creditable transmission upgrades last week, and once again, the discussion was lively.

The Markets and Operations Policy Committee on Tuesday endorsed a recommendation by the Z2 Task Force to “follow the Tariff” and reject requests that $114.1 million in directly assigned Z2 network upgrades be allocated to SPP’s base plan. The motion to reject the waiver requests passed with 83% support.

i1c7ylsacqvqtyzqavvq_full_-paul-malone-nppd
Left to right: Malone, NPPD; Johnson, AEP; and Buffington, KCP&L | © RTO Insider

The long-running issue also was a subject of discussion before the Strategic Planning Committee on Thursday.

The task force was asked by the Board of Directors to review requests from members who SPP staff said didn’t qualify for waivers from $36.9 million in directly assigned upgrade costs. The group was also asked to review another $77.2 million in direct costs from members who didn’t request waivers, while addressing “equity concerns” for both groups. (See “Z2 Task Force Rejects Waiver Requests,” SPP Briefs.)

The task force rejected the waivers by an 8-4 vote, with four abstentions.

“We didn’t look at each waiver request, but we looked at the principles and the methodologies to ensure we were treating everyone equitably,” said the task force’s chair, Kansas City Power and Light Director of Energy Policy Denise Buffington. “This kind of validates where we were in July. [Z2] is like a tug of war, where both sides have excellent points and you can empathize with both, but the flag barely moves. That’s why you saw the voting the way it is, and it’s why our recommendation is to stay the course.”

“We keep using this phrase ‘equitably,’ but it’s important to look at what equity means in this respect,” Oklahoma Gas & Electric’s Jake Langthorn said. “If the only way to resolve this is to take money from OG&E customers to give it to other customers, we simply cannot agree.”

“The reason [the motion] was characterized as ‘following the Tariff’ is because most of us believe that’s the way it ought to be,” OG&E’s Greg McAuley said.

Under Attachment Z2 of the SPP Tariff, staff was to assign financial credits and obligations for sponsored upgrades. Years of not applying credits dating back to 2008 have complicated the task of trying to accurately compensate project sponsors and claw back money from members who owe debts for the upgrades.

‘But-For’ Test

spp mopc z2 waivers
Buffington, KCP&L | © RTO Insider

“Every time we have a conversation on this, we get more information,” Buffington told the SPC. “The thing that was new to a lot of members is that the ‘but-for’ test is not a true ‘but-for’ test; it’s a 3% [usage] threshold. … People were confused about what ‘but-for’ meant under the Tariff.”

SPP’s “but-for” test requires interconnection customers to fund transmission improvements that would not be required but for their additional load. The test is triggered by a 3% increase on a line’s directional flow in the same direction as the power flow that caused the upgrade.

Dogwood Energy’s Rob Janssen was among those who asked for certainty from SPP. “The nature of the ‘but-for’ test and how it’s being applied should result in a clear statement that makes everyone comfortable,” he said.

“It would be nice to say we have a well-oiled machine going forward,” Southwestern Public Service’s Bill Grant said during the SPC meeting. “I can’t comfortably say that today.”

Prescott’s Complaint

Among those hoping for a waiver was Zachary David Wilson, an attorney representing the southwestern Arkansas city of Prescott. Wilson came to the MOPC to complain about an email he recently received from American Electric Power’s Southwestern Electric Power Co., saying the city owed $303,000 in assigned costs under a 2009 contract with AEP.

“We had a conference call with some of the [SWEPCO] lawyers to try and make some sense out of this,” Wilson said. “We would like time to investigate.”

The committee rejected the waiver request in a vote separate from the task force’s recommendation.

AEP can still use SPP’s transmission-dispute process to address Prescott’s complaint, or it can take the issue to FERC, as can other members contesting their Z2 costs or trying to gain their overdue compensation.

“Where are we going?” AEP’s Richard Ross asked during the SPC’s discussion on whether to solve Z2’s problems within SPP or at FERC. “If what we decided [Tuesday] is the course of action, I don’t think we’re going to end up solving it here. Once we enter the dispute process, my expectation is staff is not going to satisfy any of the claims folks have on their disputes, and it’s going to proceed very quickly to FERC.”

“I don’t think we can do anything about the past … people can file at FERC,” said SPC Chair Mike Wise, of Golden Spread Electric Cooperative. “I’m concerned with how we deal with this going forward.”

Process Improvements

Locke, SPP | © RTO Insider
Locke, SPP | © RTO Insider

The SPP board is expected to act on the waivers next week. After that, the task force will begin working with staff on improving the entire process.

Meanwhile, staff said it has completed its second processing run of historical costs, from March 2008 through June 2016. The results, shared with members last month, identified $183.1 million in total credits to be collected.

A third historical data processing run through August was completed Oct. 14, with results distributed to members Wednesday. The data will be used for the November invoices that will capture the complete historical period and September.

Asked whether SPP could guarantee the numbers would not change in the final invoices, the RTO’s lead regulatory analyst, Charles Locke, told the MOPC, “There are no guarantees in Z2.”

Posted on

MISO Reliability Subcommittee Briefs

MISO says it will have an easier time than expected complying with EPA’s Cross State Air Pollution Rule (CSAPR) because the final regulations are less stringent than the draft rule.

MISO Policy Studies Lead Jordan Bakke said a lot of the compliance conclusions that were made in MISO’s first study on the CSAPR have become “less relevant.” (See “MISO Releases EPA Air Pollution Rule Study and CPP Paper,” MISO Planning Advisory Committee Briefs.)

“From our reading of it, I think we can say we’re okay. There are other rules out there that are bigger changes,” Bakke told the Reliability Subcommittee.

The long-delayed CSAPR is aimed at reducing power plant emissions that contribute to ozone and fine particle pollution that is transported across state lines. Finalized in 2011, it was overturned by an appellate court in 2012 and restored by the Supreme Court in 2014. EPA says the rule, which takes effect in May, will reduce summertime emissions of nitrogen oxides from power plants in 23 states.

miso reliability subcommittee
| MISO

Of the 11 MISO states affected by the rule, Bakke said, Iowa and Arkansas now have the toughest road to compliance as their NOx budgets were tightened. MISO’s analysis also found that Michigan and Indiana now have more stringent seasonal NOx targets.

The RTO is sticking to its initial assessment that its states’ 2017 seasonal NOx budgets can be met through redispatch, although regional NOx emission trading is expected to be needed beyond next year.

Bakke said utilities can take advantage of underutilized emissions controls. Bakke also said utilities could install new controls. “That is the most comprehensive way to comply, but it has the most lead time and the most cost,” he said.

“We in the planning department have looked at this and made some suggestions, but now it’s before you,” Bakke said.

The Reliability Subcommittee sent the CSAPR issue to the Steering Committee to downgrade its urgency.

MISO Speeds Up Creation of Pseudo-Tie Congestion Management Process

MISO has proposed a pseudo-tie congestion management process that involves pre-assessment and evaluation stages before pseudo-tie registration is granted. The proposal would be implemented before year-end.

“There’s an urgency in this because we really need these processes in place for reliability,” MISO Senior Director of Regional Operations David Zwergel said.

During the 2015/16 planning year, MISO had only 155 MW of generation pseudo-tied into PJM and most of it was near the seam. MISO now has about 2,000 MW of generation pseudo-tied into its eastern neighbor and much of the generation and load being served is far from the RTO’s seam, resulting in local congestion.

MISO is proposing a new four-step process before activating new pseudo-ties:

  • MISO and a neighboring reliability coordinator determine which operational studies are needed;
  • MISO and the attaining RTO establish tests to identify market-to-market flowgates using a generation-to-load distribution factor. If the attaining RTO’s results vary from MISO’s by more than 2%, the pseudo-tie is denied;
  • MISO works out a reimbursement agreement if a pseudo-tie implementation cost allocation is needed; and
  • An asset owner and a MISO local balancing authority agree to install metering to record pseudo-tie flows as required by MISO rules.

MISO’s Kyle Abell said the RTO plans to provide Business Practices Manual and Tariff language in November, with plans for a FERC filing in December. It is asking stakeholders for feedback on the proposal by Oct. 28.

MISO Retires CIP User Group

MISO’s proposal to retire its Critical Infrastructure Protection User Group met with no stakeholder resistance. MISO’s Amanda Bragg said the group was formed three years ago to discuss industry trends and compliance with NERC’s Critical Infrastructure Protection (CIP) standards.

“Over time, the number of attendees has dwindled,” Bragg said.

Bragg also said group discussions have begun “naturally” merging CIP compliance with general information security. She said MISO plans to discuss the issues at security and compliance summits in the spring and fall, which it hopes will draw a bigger crowd.

Solid Reliability in August and September

MISO’s Steve Swan said the RTO’s reliability, markets and operational functions performed well during higher-than-average temperatures in August and September.

Average load in September was 78.8 GW, compared to last September’s 79-GW average. Load peaked on Sept. 6 at 115.1 GW.

In August, load exceeded 110 GW for 56 hours, compared to only six hours in August 2015. Average August load was 88.1 GW, 4 GW higher than a year earlier. Load peaked on Aug. 4 at 119.3 GW. Swan reported August temperatures averaged 3 to 4 degrees higher than the last three years.

“Consistent with higher loads, lower winds and stable fuel prices,” MISO said, real-time prices increased $1.02/MWh in July and $2.20/MWh in August versus 2015. Gas prices at the Chicago averaged $2.75/MMBtu, $0.11/MMBtu less than August 2015.

— Amanda Durish Cook

Posted on

Company Briefs

Oil and gas producer Swift Energy has appointed Robert J. Banks as interim CEO. He replaces Terry E. Swift, who retired as the company’s CEO earlier this month, according to a statement.

swift-energy-company-logoBanks is Swift’s executive vice president and chief operating officer and will continue in those roles.

Terry Swift led the company for 15 years. He succeeded his father, Aubrey Swift, who founded the company in 1979.

More: Houston Chronicle

Entergy Proposes $1B Gas-Fired Plant for Texas

http://logo.clearbit.com/entergy.com”>Entergy is seeking to build a $1 billion natural gas-fired power plant to serve the Montgomery County, Texas, area beginning in 2021.

The proposed 993-MW plant would serve 27 southeastern Texas counties primarily to the north and east of Houston. Entergy hopes to begin construction in early 2019.

More: Fuel Fix

GE to Spend $1.65B to Acquire Wind Turbine Blade Maker

General Electric announced last week that it plans to spend $1.65 billion to acquire LM Wind Power, a maker of wind turbine blades.

The deal will accelerate growth in GE’s renewable energy unit, which was established last year when the company acquired Alstom SA’s power operations for $10 billion.

LM Wind Power will run as a standalone business within the unit, the companies said in a statement.

More: Bloomberg News

Ranger Solar Takes First Steps to Develop Maine’s Largest Solar Farm

Ranger Solar has signed a lease for more than 600 acres at the former Loring Air Force Base in Maine to develop what could become the state’s largest solar farm, producing up to 100 MW of electricity.

The company would like to obtain the necessary regulatory approvals and power purchase agreements to begin construction before 2019.

“We know we have a long road ahead of us, but we’re committed to it. We’re hoping to bring new renewable energy to the region and new economic investment to northern Maine,” said Aaron Svedlow, the company’s director of environmental permitting.

More: The Associated Press

Duke: Plant Operating Safely After Cooling Pond Wall Break

Duke Energy said its H.F. Lee Plant in Goldsboro, N.C., is operating safely after experiencing a break 50 to 60 feet wide in its cooling pond wall.

The pond is about 545 acres and does not contain coal ash, Duke said in a press release. An actively used ash pond across the Neuse River is also safe, the company said.

Duke expects the event to contribute less than one inch of water to the Neuse River.

More: Duke Energy; The Charlotte Observer

Dynegy Delays Mothballing Illinois Power Plant Unit

Dynegy has delayed mothballing Unit 1 of its Baldwin power plant in Illinois after scoring a winning bid in the Illinois Power Authority capacity auction held in late September.

Unit 1 was scheduled to go offline on March 31, 2017, but will now remain in operation through September 2018. Unit 3 is scheduled to be mothballed on Oct. 17.

More: The Randolph County Herald Tribune

Alpha Sells Eastern Ky. Mine to Kingdom Coal

Coal company Alpha Natural Resources has sold one of its two remaining Eastern Kentucky mines to Kingdom Coal, a subsidiary of Keystone-Kingdom Resources.

Kingdom has expressed interest in restarting the mine, which Alpha shut down in July, said Alpha CEO David Stetson in a statement.

Alpha had 11 mines in Eastern Kentucky in 2012. It announced last month that it would shut down its last active mine — Sidney Coal’s Process Energy — in November.

More: Lexington Herald-Leader

NIPSCO Forecasts 24% Rise in Customer Heating Bills

Northern Indiana Public Service Co. customers should brace for a 24% rise in their winter heating bills, based on the utility’s forecast last week.

NIPSCO indicated that although higher natural gas costs are the primary driver of the hike, its gas infrastructure modernization plan is also a contributing factor.

On the same day as NIPSCO’s announcement, the U.S. Energy Information Administration predicted utility bills would increase an average of 22% across the nation this winter for households using natural gas.

More: The Times

Posted on

ERCOT Board of Directors Briefs

ERCOT on Monday released the results of planning studies under new reliability-must-run rules approved by the Board of Directors last week, confirming that Greens Bayou is still needed to support reliability in the Houston area until the new 1,100-MW, gas-fired combined cycle Colorado Bend Generating Station becomes operational in July.

The ISO also determined that removing Calpine’s 344-MW Clear Lake cogeneration facility from the system will not cause reliability concerns under the new rules, which went into effect the day after the board meeting.

The board approved three rule changes intended to improve ERCOT’s management of its RMR processes. Two of the nodal protocol revision requests (NPRRs 793 and 795) were included in the board’s consent agenda. The third, NPRR788, was unanimously approved in a separate vote after receiving four opposing votes from the investor-owned utility sector. (See “Stakeholders Send Three RMR Revisions to ERCOT Board,” ERCOT Technical Advisory Committee Briefs.)

NPRR788 requires ERCOT’s RMR planning studies to include forecasted peak loads and that a potential RMR unit must have “a meaningful impact on the expected transmission overload” to be considered for an agreement.

At last week’s board meeting, Jeff Billo, ERCOT’s senior transmission planning manager, quantified “meaningful impact” as the unloading effect a potential RMR unit would have on the transmission constraint. The unit would also need a shift factor of at least 2% and an unloading factor of at least 5% on the constraint.

“I recognize we need to make improvements in the contract analysis surrounding RMR agreements,” said American Electric Power’s Wade Smith, whose company opposed the Technical Advisory Committee’s endorsement of the NPRR. “We need to continue to work on our planning and … build transmission solutions quickly.”

Beth Garza, director of ERCOT’s Independent Market Monitor, pegged Greens Bayou’s contract — projected to cost the market $63.9 million over the course of its 25 months — as equivalent to almost 18 hours of firm load shed in the Houston area, assuming a $9,000/MWh cost of load curtailment.

“If I drive a $10,000 car, it’s ridiculous for me to pay $10,000 in premiums for the full replacement of that car,” Garza said. “Frankly, I believe the decision we made on this RMR unit is to pay the full replacement cost — the full value of the potential risk of load shed — for this unit.”

Garza noted that the Public Utility Commission of Texas has opened an RMR-related rulemaking that offers guidelines mitigating involuntary load curtailment (45927). The PUC will hold a public hearing on the issue Nov. 30.

“So things are ripe for discussion at the commission and ERCOT,” she said.

Board Approves West Texas Tx Projects

The board approved a pair of transmission projects addressing reliability concerns in West Texas resulting from load growth in the Permian Basin oil fields. The Texas-New Mexico Power rebuild of 69-kV facilities to 138 kV is projected to cost $50.6 million, while the AEP-Oncor 54-mile, 138-kV line is estimated to cost $77 million. The latter project passed with one abstention.

Luminant, TXU Energy Provisions OK’d

The board also unanimously approved staff’s acceptance of Texas Competitive Electric Holdings’ (TCEH) request that its Luminant and TXU Energy companies not be recognized as affiliates of any ERCOT member companies. The vote clears the way for the subsidiaries to seek a corporate membership in the ISO’s independent generator segment and an associate membership in the independent retail electric provider segment, respectively, replacing their prior memberships.

TCEH recently emerged from bankruptcy as a tax-free spinoff. It is composed of Luminant and TXU Energy. (See Luminant, TXU Energy Emerge from Bankruptcy.)

Bermudez Resignation Leads to Revotes

Jorge Bermudez, who resigned as an unaffiliated member of the board two weeks ago, made his presence felt with his absence. (See “ERCOT’s Bermudez Resigns from Board Position,” ERCOT Briefs.)

Because ERCOT’s legal staff determined Bermudez’s recent marriage made him ineligible to be on the board before its Aug. 9 meeting, the directors were forced to vote again on three items he moved in that meeting: the consent agenda and two proposals related to the ISO’s 401(k) plan.

Bermudez’s tenure will be celebrated during December’s annual meeting, when all directors leaving the board are honored for their service.

Board Approves 14 NPRRs, Other Changes

The board unanimously approved NPRR760, which received opposing votes from American Electric Power and Luminant last month and abstentions from CenterPoint Energy and Sharyland Utilities. The change ensures that operating days with no activity are captured in the calculation of credit variables.

The consent agenda included 13 additional NPRRs, three revisions to the Planning Guide (PGRRs) and a revision to the Retail Market Guide (RMGRR).

  • NPRR755: Allows an entity to register as a data-agent-only qualified scheduling entity (QSE) to connect to ERCOT’s wide area network (WAN) as an agent for another QSE, without meeting applicable collateral and capitalization requirements.
  • NPRR769: Clarifies the alternative-dispute resolution process to note the proceeding is the next level of appeal following ERCOT’s denial of verifiable costs. Also clarifies the confidentiality of data submitted in connection with a verifiable-cost appeal.
  • NPRR775: Strengthens the limits on fast responding regulation service (FRRS) to address future operational issues. A previous revision request (NPRR581) added limits of 65 MW to FRRS up and 35 MW to FRRS down but lacked implementation details regarding self-arrangements in the day-ahead market and restrictions on providing the service in real time without a day-ahead award.
  • NPRR778: Changes competitive retailer rules regarding move-in or move-out date changes to prevent inadvertent errors. The change should eliminate two-thirds of manual interventions currently required.
  • NPRR779 and PGRR048: Clarifies references to the Texas Reliability Entity (Texas RE) and the Market Monitor. Current protocols refer to the Texas RE in both its capacity as the Regional Entity and the Public Utility Commission of Texas Reliability Monitor. The NPRR also removes the 24-hour deadline for ERCOT to notify the reliability monitor of a failure to provide ancillary services. The new language clarifies that the Market Monitor is an included party in several provisions related to the ERCOT stakeholder process.
  • NPRR781: Addresses the market’s growing use of advanced metering systems (AMS) by updating protocol language to clarify purpose and definitions, update processes and methodologies and remove outdated ones.
  • NPRR782: Removes inconsistencies in protocol language by changing the equations governing the settlement of ancillary services. The change affects resources unable to deliver on their ancillary service obligations because of transmission constraints.
  • NPRR785: Allows ERCOT to automatically prepopulate current operating plans (COP) for wind and photovoltaic resources with the most recent forecast for the next 168 hours. QSEs representing these resources can either submit the prepopulated forecast as the COP by default or submit a lower number.
  • NPRR786: Corrects the allocation of transmission losses, distribution losses and unaccounted-for energy (UFE) so that negative loads do not result in the loss of UFE allocations.
  • NPRR787: Removes the requirement that the QSE receiving a verbal-dispatch instruction confirmation include the name of the individual that received the confirmation within the electronic acknowledgement.
  • NPRR789: Requires ERCOT to publish all its midterm load forecasts for market participants and note which one is currently being used by operations. The ISO currently publishes several forecasts per weather zone but only makes one at a time available to the market.
  • NPRR793: Adds several responsibilities for RMR unit owners, revises RMR formulas and makes other clarifications to ensure RMR units are not accidentally committed as a reliability unit before other resources.
  • NPRR795: Creates a mechanism to refund capital expenditures funded by ERCOT under an RMR agreement.
  • PGRR047: Requires energy developers seeking an interconnection agreement to include among their materials a signed affidavit that they have notified the Department of Defense of their proposed project and have requested a review.
  • PGRR049: Removes the option to submit generation interconnection or change request (GINR) applications through standard mail or fax and updates the mailing address for GINR payments to ERCOT’s treasury department.
  • RMGRR134: Gives non-modeled generators the option to use the AMS data-submittal process and clarifies processes for unregistered distributed generation versus registered non-modeled generators.

— Tom Kleckner

Posted on

PJM Considering Injection Rights for Demand Response

By Rory D. Sweeney

VALLEY FORGE, Pa. — PJM is considering giving demand response participants injection rights in its effort to expand distributed energy resources’ access to wholesale markets.

The effort is being overseen through special Markets and Reliability Committee sessions that began in April. At the most recent session last week, PJM officials discussed what they called “demand response with injections,” a practice ISO-NE has been using since last year.

pjm dr demand response with injections
PJM’s interconnection rules restrict DER system designs and limit their full capability use. | A.F. Mensah

DR resources eligible to inject past their meters would have to do so without creating problems for the distribution system. To avoid double counting, DR resources would not receive payments for regulation or synchronized reserves if they are reducing their energy bills through net energy metering (NEM).

Accounting, Jurisdictional Questions

Allowing DR injections raises jurisdictional and accounting questions, PJM said. If DR is treated as a non-wholesale energy injection akin to NEM, “does the DR resource get paid LMP and keep the NEM credit? Does PJM adjust the energy payment to the DR resource to reflect NEM credit? Does the [load-serving entity] keep the cost reduction?”

PJM’s Aaron Berner also reviewed the small generator interconnection process and whether the alternate queue for small projects should be eliminated or modified. The proposals, presented by Berner, included an alternative queue process designed to reduce the study and review times as well as a reorganization of grid-upgrade cost allocations for projects costing less than $5 million.

The sessions are in response to a problem statement brought by battery storage system designer A.F. Mensah, which was approved by stakeholders in February. (See “Faster Path to Market for Distributed Resources to be Studied,” PJM MRC & Members Committee Briefs.)

In the problem statement, A.F. Mensah outlined the limitations created by PJM’s current market participation rules that require battery systems to commit to a single purpose rather than provide multiple services. To participate in PJM’s markets, versatile resources like battery systems must choose to interconnect either as a generation resource through the RTO’s standard queue or as a DR resource.

Cost Prohibitive

The standard queue is cost prohibitive, requiring a long review and analysis process, along with requirements to install redundant equipment that increase each project’s complexity and cost. Additionally, that path limits storage systems to participating in the wholesale market, so retail customers with small-scale renewable systems, such as rooftop solar or residential-size wind turbines, have to account for each system separately and can’t store renewable power created now to offset demand later.

However, the DR pathway only allows resources to offset their owners’ current demand, which negates renewables’ ability to provide power to the grid when they are producing more than the system owner needs.

“Distributed resources are often installed as part of a wider behind-the-meter system, which includes solar panels that produce more power than consumed by the load on an instantaneous basis,” A.F. Mensah wrote in the problem statement. “The provision limits the DR value opportunity based on the amount of instantaneous load, which therefore severely limits the value the DR resource can provide to the market.”

PJM’s issue charge set up the special MRC sessions in acknowledgement of no other cross-committee forum existing to address the topic.

‘Next Wave’

“I can see DER participating in PJM as the next wave of a resource that at some point is going to reach critical mass,” said Dave Pratzon, who consults for generators and energy marketers. “It’s going to have to be dispatchable. PJM’s going to have to know its output. I think that part of the work of this group has to be forward looking.”

PJM also presented its initial considerations on the topic, suggesting there could be a hybrid rule. Calling it “demand response with injections,” PJM’s Andy Levitt said ISO-NE instituted a similar rule in 2015 that allows load to “go negative” — i.e., inject excess generation into the grid. This model would necessitate changes to accounting and settlement procedures to ensure participants are paid appropriately.

PJM staff asked if stakeholders would allow them to focus on one issue, such as allow DR injections for ancillary services, so as to not overload the committee and “boil the ocean,” as MRC secretary Dave Anders put it. Stakeholders, however, didn’t want the other issues to be forgotten and said ancillary services might be one of the harder issues to address.

“I don’t think this is a quick one that we can overlook in a hurry,” FirstEnergy’s Bruce Remmel said. “It complicates itself quickly.”

PJM staff are analyzing the feedback from the meeting and will be presenting recommendations on how to proceed. The next meeting on the issue is scheduled for 9 a.m. Nov. 22 at PJM’s Conference and Training Center.