Page 1332 – RTO Insider

April 11, 2017

MISO Stakeholders Question Electric-Gas Info Sharing

By Amanda Durish Cook

CARMEL, Ind. — MISO is preparing nondisclosure agreements and associated Tariff language to share gas usage estimates with pipeline operators, but some stakeholders are voicing reservations about the pilot program.

The RTO says the nondisclosure agreements will be required before staff of pipelines or local distribution companies can view hourly burn estimates based on the day-ahead market clearing. “MISO will not share any information before that signed nondisclosure agreement,” Mark Thomas, MISO manager of gas-electric coordination, told the April 6 Reliability Subcommittee meeting.

MISO has lined up three gas system operators for “limited sharing” of day-ahead gas usage profiles in 2017 under the pilot program, an effort to ensure gas-fired generators have fuel when they need it.

The RTO said it will outline the use of the nondisclosure agreements in section 38.9.1(A) of its Tariff and file the changes with FERC by April 26. Thomas asked for stakeholder comment on the language insertion by April 13.

MISO said it would wait for FERC acceptance before sharing profiles. Thomas said the RTO has not yet determined at what frequency the information would be provided.

Multiple stakeholders voiced apprehension that reliability will be harmed if operators act on partial, estimated data provided by MISO. Subcommittee Chair Tony Jankowski questioned why the RTO would move ahead on the program with what he said was incomplete data based solely on day-ahead market activity.

Phil Van Schaack, MISO gas-electric operations coordinator, reminded stakeholders that the program is a pilot and insisted the sharing of generator start and stop times and estimated burn rates will be helpful. “This is a way to start the exchange of some data,” Van Schaack said. “The pipeline operators are excited by this.”

Thomas said if the pilot program does result in the sharing of “bad information,” MISO will scrap the program.

Indianapolis Power and Light’s Lin Franks said that while she is usually “all for” the sharing of information, the pilot program could cause problems. If MISO’s information clashes with generator operators’ information, they might be in the position of defending their efficiency, she said.

“You’re feeding the public frenzy of challenging other people’s data, if this becomes public,” she said. “This does absolutely nothing for resource adequacy.”

MISO said the pilot was authorized by FERC Order 787, which allows RTOs to share nonpublic information with gas operators. Previously, staff has said that the RTO is not attempting to influence generator behavior with the use of hourly profiles. (See MISO to Continue Gas-Electric Coordination Efforts in 2017.)

“MISO believes that sharing nonpublic, operational information with gas system operators can increase reliability for both industries,” the RTO said in a presentation. “Gas usage profiles, notably in severe operating conditions, will increase fuel assurance and reliability for gas-fired generators and will facilitate lines of communication with gas system operators.”

April 11, 2017November 13, 2023

ERCOT Board of Directors Briefs

Wind energy and other renewable resources are providing so much of ERCOT’s generation mix that not even the ISO can keep up.

Delivering his CEO report to the Board of Directors, Bill Magness said ERCOT on March 23 had finally reached the 50% wind penetration mark — a percentage he said would have reached 55% had another 1,500 MW of wind energy not been curtailed. (See ERCOT Reaches 50% Wind Penetration Mark.)

Not included on the slide, which was produced to meet an earlier board deadline for the April 4 meeting, was ERCOT’s latest record for wind generation. That came March 31, when the ISO reported 16,141 MW of wind generation at 8:56 p.m., almost 40% of the total load.

The previous record came last Christmas, when ERCOT saw 16,022 MW of wind generation.

ERCOT has 18,064 MW of installed wind capacity, with just more than 10,000 additional megawatts that have interconnection agreements, according to its latest generator interconnection status report.

The ISO has also seen a rapid increase in solar energy, Magness said, though not at the scale of wind resources. He said ERCOT’s solar capacity nearly doubled in 2016; it currently has 556 MW of capacity and another 2,009 MW have interconnection agreements.

To help address the continued increase in variable generation, ERCOT has added a sixth desk in its operations center that is focused on reliability risk. The new desk went live in January and will respond to wind and solar forecasts errors, net load ramps, low inertia and variable ancillary service needs.

“Because of our changing resources, certain things have grown over time to be much bigger issues than they traditionally have been,” ERCOT Senior Director of System Operations Dan Woodfin told the board in a separate presentation.

Woodfin was recently honored by the Utility Variable-Generation Integration Group with an award for “sustained leadership” in integrating variable generation. He said reliability risk increases as more renewables are added to the Texas grid.

“We have the same percentage of forecasting error, but the number of [renewable] megawatts in any given hour will be higher,” Woodfin said. “We want to assess them in real time, not just quarterly or at the beginning of the year.”

“The things we’re doing and the investments we’re making are just part of the day-to-day business as we adjust to these changes,” Magness said.

He said training staff would be a “big priority” the next couple of years. “We’re training our operators and giving them as much simulation of the conditions they’re seeing on the grid they’ve never seen before. We’re taking as much advantage as we can of our operational expertise to prepare for the future.”

Higher Capacity Factors Increase Wind Energy’s Output

The Independent Market Monitor’s report picked up on the renewables discussion, with Director Beth Garza highlighting wind energy’s growing share of ERCOT’s fuel mix. Wind produced 15% of ERCOT’s power last year, up from 3% in 2007. Coal has seen its fuel share drop from a high of 40% in 2010 to a low of 28% in 2015, while gas has ranged from 38 to 48%.

“More wind is displacing some of the fossil fuels as the price disparities between gas and coal change through time,” Garza said.

She attributed much of the growth to wind energy’s higher capacity factors, a “reflection of improving and increasing technology.” Garza said the Monitor is also seeing an increase in installations on the Gulf of Mexico because the “wind output coincides more with load requirements” peaking in the afternoon.

Raising the question as to whether coal is “on the way out,” Garza pointed out that ERCOT’s coal fleet is “vintage.”

“What we see with our coal fleet,” she said, “is that the bulk of it was installed in the 70s and 80s. It’s achieving the end of its economic life as we speak.”

Ending Greens Bayou RMR to Save $21.9M

Magness told the board that terminating NRG Texas Power’s Greens Bayou Unit 5 reliability-must-run contract early will save the ERCOT market $21.9 million. He credited efforts made by staff and stakeholders to change protocols and criteria for reviewing RMR contracts, saying they “clearly had a big impact and allowed us to make this change.”

He also pointed to the Public Utility Commission of Texas’ RMR rulemaking, which is currently open to comments. The rule changes include requiring board approval of RMR contracts and adjusting the notice requirements and complaint timeline applicable to suspending a resource’s operation. (See “PUC Approves ERS, RMR Rulemakings,” Texas PUC Briefs.)

The Greens Bayou RMR contract was approved last June and scheduled to last through June 2018. It was expected to cost the market more than $58 million, but that number was revised down to $43.9 million in February. Instead, the early termination means ERCOT will only have made $22.1 million in standby payments to NRG at $3,185/hour during on-peak hours for the Houston-area plant.

ERCOT announced the contract’s termination in February. It said studies using new criteria indicated the unit would not be needed for transmission system reliability after Exelon’s 1,148-MW Colorado Bend II Generating Station in nearby Wharton County becomes operational in June. (See ERCOT Ending Greens Bayou RMR May 29.)

Magness also told the board that ERCOT now declares level 3 energy emergency alerts (EEA3) when operating reserves hit 1,375 MW, as required by NERC reliability standard EOP-011-1.

The ISO’s normal operating procedure had been to declare an EEA3 and load shed when reserves fall to 1,000 MW. It has revised its procedures to still go into load shed at 1,000 MW but declare the EEA3 earlier. Staff is drafting a revision request to change the EEA3 trigger in the protocols.

“Our studies have indicated as long as we have sufficient responsive reserves, we’re able to maintain and not need to go into load shed until 1,000 MW,” Magness said.

Dallas Fed: Texas Surviving an Oil Bust

Mine Yücel, senior vice president and research director for the Federal Reserve Bank of Dallas, once again delivered an annual report on the Texas economy, saying the state has survived the recent energy bust “with few deep scars.”

Yücel pointed to a 2.7% employment growth rate and 54,500 jobs created in the first two months of 2017, this after a 1.7% growth rate and 203,000 new jobs last year. The Fed is projecting a 2.3% growth rate and 280,000 new jobs in Texas this year.

“The worst may be behind us, but of course, we have quite a few risks,” Yücel said, alluding to oil prices and the dollar’s strength.

Despite a slowdown in the Permian Basin and the rest of the oil patch, Texas still saw more than 210,000 people migrate to the state from July 2015 to July 2016. That was a drop from about 260,000 the year prior and trails Florida nationally, but still outpaces California, New York and Illinois.

Multi-Interval

ERCOT Commercial Operations Vice President Kenan Ögelman shared staff’s Multi-Interval Real-Time Market (MIRTM) feasibility study with the board, getting little pushback with his recommendation that now is not the right time to implement the market.

Ögelman said the estimated $20 million cost of the market’s software would not produce sufficient production cost savings. The Technical Advisory Committee reached the same conclusion last month. (See ERCOT Technical Advisory Committee Briefs.)

“The study found there were production cost savings, but that was in the environment of $2 to $3 gas,” he said. “Unless you see gas prices driving up, I’m trying to create savings off a very low baseline price.”

ERCOT dispatches its market in five-minute intervals. Staff and stakeholders have been discussing potential alternatives under different names (look-ahead security-constrained economic dispatch, multi-interval SCED, etc.) since 2011.

“The question has been, can we improve the market’s efficiency and functionality by looking ahead longer than five minutes. At 15 minutes, we were more accurate with the forecast, but we left a lot of resources behind,” Ögelman said, referring to fast-responding resources and load resources that currently participate in the real-time market through voluntary self-commitment.

Ögelman said the TAC had assigned the Wholesale Marketing Subcommittee to consider whether real-time co-optimization might be a better solution to pursue. The subcommittee held a preliminary discussion April 5.

“It’s been dormant for a while,” Ögelman said of the optimization discussions. “There’s a need to get everyone up to speed on how it works.”

Board Approves 16 Revision Requests

The board’s consent agenda, approved unanimously, included 10 nodal protocol revision requests (NPRRs) and three revisions to the Planning Guide (PGRRs).

NPRR776: Aligns protocol language with currently used verbal communication practices between transmission service providers (TSPs), qualified scheduling entities (QSEs) and generation resources. Also identifies new requirements for data that TSPs provide to ERCOT, QSEs and generators. The committee tabled NOGRR167, which aligns the Nodal Operating Guide with NPRR776.
NPRR799: Requires that TSPs and resource entities — generation and load that can reduce electricity usage or provide ancillary services — submit updates to the outage scheduler within one hour of the facility’s outage start or completion.
NPRR802: Clarifies current settlement practices and protocol language, including how reliability unit commitment resources opting out of RUC settlement are treated in calculating real-time online reserve capacity.
NPRR804: Clarifies that ERCOT should post both a systemwide network model and a set of station one-line diagrams, and that the model posting does not disclose data about private-use networks.
NPRR808: Extends the congestion revenue right (CRR) auction process into the third year forward, revises the percentages sold in the auction’s long-term sequence and aligns modifying load zones to the timetable.
NPRR809: Defines the terms “initial energization” and “initial synchronization;” adds a reference to a quarterly stability assessment for interconnecting generation resources when evaluating the need for a generic transmission constraint; and clarifies a resource’s requirements prior to initial synchronization.
NPRR810: Removes the applicability of an RMR’s incentive factor to reservation and transportation costs associated with firm-fuel supplies, and accordingly separates costs in the RMR standby payment equation.
NPRR812: Clarifies short-term system adequacy report language; aligns protocol language with current ERCOT practices and Texas PUC rules for posting resource and load information; and modifies the requirement for posting a RUC initial-conditions report to only include the process as originally intended in NPRR314.
NPRR813: Requires references to service organization controls for the annual ERCOT market settlement audits.
NPRR818: Clarifies that the ISO can curtail DC tie loads during a watch, before declaring an emergency condition. (See ERCOT Stakeholders OK Change to DC Tie Curtailments.)
PGRR052: Ensures a new generating unit’s operating limits are established by setting a timeline for stability studies following a full interconnection study (FIS), incorporating model data or transmission system changes, not known during the FIS, before a new unit is brought online.
PGRR054: Clarifies the content, review period and process for posting an FIS’ results, and establishes a process for identifying, proposing and implementing solutions to stability issues identified during the FIS.
PGRR055: Defines the process for revising the Planning Guide to first consider PGRRs at the subcommittee level.

— Tom Kleckner

April 10, 2017

Stakeholders Advance on Western Regional Forum Proposal

By Robert Mullin

Participants in a West-wide forum created by CAISO to discuss issues related to the Energy Imbalance Market (EIM) want to move quickly to complete an evaluation that will shape the group’s future role.

One point of difference has arisen among stakeholders: disagreement over whether the Regional Issues Forum (RIF) should produce its own recommendations on matters affecting the EIM.

RIF members are in “considerable” alignment over what structure and procedures the group should adopt within the EIM’s governance framework, according to a draft issue paper detailing members’ evaluations.

They also agree they can meet a July deadline to present the EIM’s Governing Body with a final proposal outlining the RIF’s procedures and responsibilities.

The RIF was established in 2015 as CAISO began its effort to expand its operations into other parts of the West. The forum was conceived under the EIM charter as an informal body to allow stakeholders and the public to discuss wide-ranging issues related to the West’s only real-time energy market.

Five Sectors

The forum is organized along five industry sectors: independent power producers and power marketers; transmission-owning utilities; publicly owned utilities; consumer advocates; and balancing areas neighboring the EIM. Each sector appoints two liaisons as representatives.

The EIM charter calls for the Governing Body and stakeholders to begin re-evaluating the continued existence of the RIF this month.

During a Feb. 28 joint meeting of the Governing Body and RIF, a consensus emerged that the RIF should be preserved. (See Western Stakeholders Support Continuing Regional Forum.)

But one “existential” question arose, according to Governing Body Vice Chair Doug Howe: What’s the RIF’s purpose?

Stakeholders and their liaisons are still seeking to develop an answer.

The issue paper notes that the RIF’s operating guide “is limited in detail” but “clearly contemplates the possibility of the RIF providing recommendation or written work products on issues.” The guide also allows the group to establish a procedure to express a common position.

caiso eim western regional forum proposal — Braun | © *RTO Insider*

“Of all the issues that we got written comments on, the issue that the RIF acting through the liaisons should produce written opinions or recommendations on market design issues was clearly the one in which we got the most disparate comments,” RIF Chair Tony Braun said during an April 7 call to discuss the issue paper.

Powerex opposes the RIF making any formal recommendations, contending that the group’s membership is limited and does not represent the market as a whole. The company wants the RIF to be opened up to a larger number of sectors.

“We think that the current sector definitions are fairly inclusive,” Braun said, speaking on behalf of the liaisons, adding that “if there are additional improvements we need to make in that regard, we certainly would encourage comments.”

Disagreement over RIF Work Products

PacifiCorp, the EIM’s first member, said the RIF should only produce summaries of stakeholder discussions and comments on particular issues, while Portland General Electric thinks that positions should be communicated only by individual stakeholders or “voluntary alignments” of sectors.

Both the California Municipal Utilities Association and Puget Sound Energy recommend maintaining the option of generating written opinions, but only under “detailed” procedures setting out how to produce the papers and capture majority and minority positions. The Natural Resources Defense Council, Public Generating Pool (PGP), Western Resources Advocates and the EIM’s Body of State Regulators (BOSR) largely backed that view.

While the liaisons acknowledged that producing position papers would increase the RIF’s workload and change the character of the group’s meetings, Braun said they wanted to retain the option of producing written work.

“We’ve created … a trigger whereby written work products would be triggered by specific requests,” Braun said. “The requests would come from the EIM governance structure and also would come with a host of procedures that would need to occur.”

Therese Hampton, a liaison from PGP, pointed out that stakeholders generally agreed that the RIF should continue to meet three times a year but reserve the option to convene more frequently if issues warrant — or if requested by the BOSR, the Governing Body or stakeholders. The issue paper suggests that RIF meetings be coordinated with those of the Governing Body, a position with strong stakeholder support.

RIF liaison Matt Lecar, principal at Pacific Gas and Electric, pointed out that the liaisons were proposing a quorum provision requiring at least one liaison from each sector to attend each meeting.

Sara Edmonds, general counsel at PacifiCorp Transmission, said the liaisons have so far discerned “no obvious need” for changes to the EIM’s governing charter or the RIF’s operating guidelines.

“We also note that there would be a need for the ISO’s legal department to take a look at the governance documents following the conclusion of this reevaluation process,” Edmonds said.

Stakeholder comments on the proposals set out in the draft issue paper are due May 3.

“We appreciate all the attention and input that we’ve gotten in the RIF meetings,” Braun said. “And we’d greatly encourage stakeholder comment, because we can’t anticipate all the issues in here.”

April 10, 2017

MISO to Make Up Manitoba Hydro Reserves During Spring Outages

By Amanda Durish Cook

CARMEL, Ind. — Manitoba Hydro will reimburse MISO for providing extra contingency reserves during May, when maintenance outages are expected to reduce transfer capability between the Canadian utility and the RTO.

The MISO/Manitoba Hydro Contingency Reserve Sharing Group has a 2,000-MW contingency reserve requirement, with MISO ordinarily supplying 1,850 MW and Manitoba Hydro responsible for 150 MW.

Although Manitoba Hydro expects bountiful water supplies for May, maintenance outages will reduce the transfer limit between it and MISO below normal minimum cleared energy levels for the month, officials told the April 6 Reliability Subcommittee (RSC) meeting.

Following discussions between MISO staff and the Manitoba Hydro Electric Board, the RTO agreed to clear the utility’s share of contingency reserves, resulting in an additional 60 MW of spinning reserves and 90 MW of supplemental reserves.

Manitoba Hydro transfer capability miso — Swan | © *RTO Insider*

“Much of the [maintenance] work is on the U.S. side of the border, but the MISO-Manitoba transfer capability will be reduced … during the work,” said Steve Swan, MISO senior manager of dispatch and scheduling.

Swan said Manitoba Hydro will still have reserves but might not be able to supply them because of the outages. “I think rather than saying they have reserves, they’ll have water,” Swan said.

A Manitoba Hydro representative confirmed the utility will have sufficient water to supply reserves but could encounter difficulties delivering them because of insufficient transmission capacity.

The utility has agreed to reimburse the MISO loads charged for contingency reserves through a miscellaneous charge in settlements for the entire month because transfer capability will be difficult to forecast.

“We will be carrying them for the entire period, and they will be reimbursing us for the entire period,” Swan said. “This was the best solution we could come up with.”

Manitoba Hydro will post updated limits during maintenance to MISO’s OASIS site. Swan said changes to the RTO’s clearing requirement will begin April 31.

Stakeholders at the RSC meeting did not appear to have a problem with MISO’s plan.

“That’s what I think the market is for,” RSC Chair Tony Jankowski joked.

At this year’s Gulf Coast Power Association MISO South Regional Conference, MISO CEO John Bear said he wished the RTO boasted more hydro power in the footprint and that one of its biggest contingencies is the transmission line connecting it to Manitoba Hydro.

Manitoba’s hydro exports to MISO are expected to increase in 2020 when the 500-kV line Great Northern Transmission Line between the province and Minnesota is scheduled to go into service. (See Manitoba-Minnesota Tx Line Granted Rate Incentives.)

Belt-Tightening

Manitoba Hydro, which underwent a management restructuring in February, last week began offering voluntary buyouts in an effort to cut 15% of its workforce and save about $60 million, CBC reported. The utility’s debts — $13 billion debt as of late 2015 — could increase to $25 billion over the next three years, according to CBC.

April 10, 2017

EBA Panel: CPP’s Demise not Certain — and it Doesn’t Matter

By Rich Heidorn Jr.

WASHINGTON — The Trump administration may not succeed in killing EPA’s Clean Power Plan — and it doesn’t matter anyway because the power industry’s decarbonization will continue without the rule, speakers told the Energy Bar Association’s annual meeting last week.

EBA trump clean power plan — Panelists left to right: Doniger, Bumpers and Connor | © *RTO Insider*

The Natural Resources Defense Council’s David Doniger, utility attorney William M. Bumpers and J.P. Morgan investment banker Ian C. Connor gave a general session audience their predictions on how the power industry will respond to President Trump’s March 28 executive order directing EPA to undo the CPP.

Here’s a summary of what the EBA audience heard.

NRDC: The ‘Trumpocene’ Era Won’t Last

David Doniger, director of the NRDC’s Climate and Clean Air program, said that most of the players in the electric industry have adjusted to the CPP’s goals and are unlikely to reduce decarbonization efforts because of Trump’s executive order. (See Trump Order Begins Perilous Attempt to Undo Clean Power Plan.)

“We’re now entering what I’ve started to call the ‘Trumpocene,’ which … I hope [will be] a very short geological era with a maximum life of four years,” Doniger said. “Many people in the industry have to be thinking, ‘How long is the Trumpocene? Do I change my plans because of this coal industry- and ideologue-driven executive order and attempt to roll back the Clean Power Plan? Do I bet that that will succeed?’

“Because executive orders don’t actually do it,” he continued. “When it comes to changing rules that have been adopted under the Clean Air Act … you can’t tear the building down except by using the same rulemaking methods and procedures that it took to build the building up. So what’s begun here last week is a long slog of rulemaking process that may or may not produce the scrapping of the Clean Power Plan … and if he does that, it may or may not withstand judicial scrutiny.”

Doniger said CPP opponents may fail because they use unrealistic data in support of their case, noting the study contracted by CPP opponents that estimated the cost of compliance at $39 billion, about five times EPA’s estimate. He also noted the president’s executive order requiring changes to the calculation of the social cost of carbon.

“So they’re going to walk into court with an arbitrarily high-cost estimate and an arbitrarily low-benefits estimate. And they’re going to lose. So the CPP ain’t dead yet.

“So if you’re an executive or an adviser to an executive and think, ‘Well I really do think climate change is a real problem’ … and you’re making investment decisions that have a 20-year life or more, do we bet that over those 20 years that the Trumpocene will continue? No. I don’t think that’s a good bet.

“We hear … from companies and state regulators … that they are continuing to plan on the trend of decarbonization — at least that much of it which is supported by market forces. This is based on the anticipation [that] either the repeal plans won’t actually succeed — like say, for example, the immigration plan or the health care plan — or that they will be a mere blip because the next president will return to a path that’s more reality-based.”

Doniger said industry trends favoring low-carbon resources need to be buttressed by government policies.

“I think the markets are running in the right direction. Obviously technology is running in the right direction. But you really can’t foresee that they would make the deep decarbonization in the time frame we need,” he said. “So we need some form of policy. … To paraphrase Donald Rumsfeld: ‘You fight climate change with the Clean Air Act you have, not the one you wish you had.’”

Utility Attorney: CPP Would Be Ineffective

Baker Botts attorney William M. Bumpers, who has represented utilities including Southwestern Public Service, Reliant Energy and Entergy, said although he is a strong advocate of reducing carbon emissions, he is not a fan of the CPP.

“I really didn’t like the Clean Power Plan for a host of reasons. One is that I think it was going to be largely ineffective,” he said. “Fifty percent of the reductions they were claiming credit for had already been achieved by the industry with no particular help from the federal government.”

Bumpers also said EPA’s regulatory approach “was sort of a square peg, round hole problem.”

“When they overlay basically three different types of emissions trading — most of which wreak havoc with each other — my own view is it was going to create one of the largest bureaucratic messes with regulatory overreach that was going to create more ossified limitations on the development in the industry than it was going to help.”

Bumpers said he would like to see a ruling by the D.C. Circuit Court, which heard arguments on state challenges alleging EPA overstepped its authority in September. The Supreme Court stayed the rule pending resolution of the challenges. (See Analysis: No Knock Out Blow for Clean Power Plan Foes in Court Arguments.)

“In some ways, I think the industry would benefit from having the D.C. Circuit rule because [there are] elements of that plan that the D.C. Circuit would probably strike down — maybe whole large portions of it.”

Bumpers said he represented utilities before EPA in an effort to improve the plan before the final rule was released in August 2015. “We … succeeded to some extent, but [the plan] ended up in bad shape and I ended up representing five companies as part of a challenge,” he said. “I represented probably 20 other companies who were equally as involved who in the end said, ‘We don’t care because it doesn’t affect us. It really doesn’t change our business plan one iota.’

“What it would have done is really substantially affected a handful of states and had no effect on most of the rest. It just didn’t make sense to me.”

Bumpers said his clients would like “a very state-oriented, federalist approach in which states have the opportunity to deploy the resources at their hand based on their resource mix to try to address climate change, and make it less of a nationwide, one-size-fits-all trading program but allow states to tailor their own programs.”

He criticized moves by Trump and congressional Republicans to roll back Obama administration efforts to limit methane emissions from natural gas production. “The path forward is going to result in a whole lot of new natural gas [generation]. … That’s what’s driving coal plants out of business, [and] it’s helping to reduce our carbon footprint within the industry. But if [at] the same time we don’t have rigorous oversight of the drilling and production facilities to reduce methane, we will have shot ourselves in the foot.

“At best, [the CPP] was going to accelerate where the CPP wants us to go by a couple of years. And at this point — given the stay — if it were reinstated, I don’t think it would do anything, assuming there’s a delayed implementation schedule.”

J.P. Morgan: Industry to Decarbonize with or Without CPP

Ian C. Connor, global co-head of J.P. Morgan’s Power & Utility Group, largely agreed with Bumpers’ position on the CPP.

“I think that the CPP — whatever its noble objectives — it’s relatively irrelevant whether or not it’s enforced … I have little doubt, consistent with what Bill said, that the industry will materially decarbonize and outstrip what the CPP is trying to do.”

Connor said the CPP could actually limit options for controlling carbon emissions in the future.

“At a time of rapid change, I think you want to make sure that you keep absolute optionality,” he said. He noted that although the U.S. did not sign the 1997 Kyoto protocol, it has still reduced carbon emissions since then — in part because of improvements in gas drilling practices and increased energy efficiency.

The U.S. has “actually outperformed most of the signatories of Kyoto. It’s also outstripped the Waxman-Markey objectives as well,” he said, referring to the cap-and-trade bill that faltered in Congress in 2009. “That’s largely driven by technology. Going back to 1997 … no one had any idea the shale revolution was coming.”

The drop in the costs of natural gas has eroded coal’s share of the generation mix. And now, renewables’ dramatic cost reductions are providing competition to gas.

“Today, renewables on a levelized cost basis — wind and solar — are cheaper than an efficient [combined cycle] natural gas plant. And all of these are materially cheaper than coal,” he said.

“To give you an idea of how [quickly] things are moving … six months ago we were talking about a [power purchase agreement] being signed for wind at $20/MWh. … That’s shockingly low. Today it’s $15 to $17/MWh. So in six months the cost of wind has declined 15 to 25%.”

Nuclear not Coming Back

Bumpers and Connors also agreed in their gloomy view of nuclear power’s role in a low-carbon future.

“Nuclear is not coming back,” Bumpers said. “Nobody can afford the balance sheet risk associated with a nuclear plant. So unless we get some super cheap, modular technology, I don’t see that happening.”

Connor noted the cost overruns at plants being built for Southern Co. and SCANA and the bankruptcy filing by Westinghouse, the main builder of the plants.

“It’s really hard to go in to your regulators or anyone else and say ‘I need to build this thing if the levelized cost is way up here and wind and solar are way down here and gas is down here.’ You can’t make the argument anymore.”

April 10, 2017

Overheard at the Energy Bar Association Annual Meeting

WASHINGTON — More than 400 FERC officials, energy lawyers and stakeholders attended the Energy Bar Association’s annual meeting last week. Here’s some of what we heard.

Energy Efficiency ‘Most Expensive’ Form of Energy?

energy bar association solar ferc — Nemtzow | © *RTO Insider*

David Nemtzow, director of building technologies for the Department of Energy’s Office of Energy Efficiency and Renewable Energy (EERE), described energy efficiency as “a Swiss Army knife.”

“The benefits are multiple. … For some people and some users and some policymakers, the environmental benefits are central to energy efficiency. For others, it’s the economic savings. For others, it’s the jobs. It’s all the above.”

Bill Campbell, general counsel and head of sustainability and structuring for Equilibrium Capital, doesn’t agree with those who say that energy efficiency is the cheapest form of energy.

“We say that because we focus on the amount that’s paid in incentives. In fact, it’s probably the most expensive form of energy on the planet, but that’s OK. The reason it’s the most expensive form of energy on the planet is that every time you subtract a unit that’s saved with energy efficiency, the utility would lose the retail price of that unit. … Recognize that that just establishes the competitive marketplace for efficiency.”

Community Solar Gardens Overhyped?

Minnesota attorney Jeff Paulson, who represents community solar developers, is bullish on distributed energy. But he has heard the naysayers.

“There is a commissioner in the Midwest, who shall go unnamed, who has referred to community solar gardens as ‘the new kale,’ because of the rapid growth in popularity, and [because] we’re attributing so many … benefits that are supposed to be derived from introducing them on your system,” he said. “Maybe some of the talk about community solar gardens is a little hyperbolic. But that doesn’t mean — like kale — that there aren’t some benefits to still be derived.

“It’s a tough market out there right now [for developers] trying to do avoided-cost deals or trying to do utility-scale [projects] in states that are not favorably inclined toward that. This is a huge market opportunity.”

Paulson said he’s been frustrated with the pace of Minnesota regulators’ actions on community solar.

“There’s a lot of good things being done [in Minnesota]. There were [also] a lot of disputes. There was a lot of process,” he said. “I will say that 18 months into that regulatory process I was sitting at the table in front of the commission just screaming for them to shut the heck up and stop trying to make this program perfect. Get it defined. Let us get out in the field and start building projects and getting the financing.”

Incoming EBA President Calls for ‘Civility’

Robert Weishaar was elected as the EBA’s new president, succeeding Emma Hand. In lunchtime comments after the transition, Weishaar praised Hand for making “diversity and inclusion a focal point” of her term as president. He pledged to continue the work of Hand and President-elect Matthew Rudolphi, who led a task force that developed what he called the “strong diversity and inclusion initiatives” adopted by the EBA.

“EBA remains dedicated to the value of diverse perspectives,” said Weishaar, an attorney with McNees Wallace & Nurick who represents industrial consumers and owners of cogeneration facilities. “While not losing sight of that core value, we need to focus on another. The current dynamics of our profession and the challenges currently facing our country also demand a recommitment by all EBA members to collegiality and civility in our profession and in our day-to-day [actions].”

– Rich Heidorn Jr.

April 10, 2017

NYISO Auction Shows Higher Prices for NYC, Hudson Valley

By Michael Kuser

NYISO’s summer 2017 capacity auction results surprised analysts last week with higher-than-expected prices for New York City — up 72 cents year over year to $11.71/kW-month.

Prices for the Lower Hudson Valley rose even more, jumping $2.25 to $10.50/kW-month, while the Rest of State dropped 62 cents to $3. Long Island was up $1.50 to $5.79.

In an April 5 market analysis, UBS Securities analyst Julien Dumoulin-Smith said the results were higher than “we had initially expected as a new, more bearish demand curve was put into effect alongside weak demand forecasts.”

Retirements and New Entry

The results indicated that the 312-MW Cayuga coal-fired plant — which is operating under a reliability support services agreement with New York State Electric and Gas that ends in June — cleared the auction. Without higher prices, however, Cayuga Unit 2 could face retirement next year because of environmental upgrades needed to operate past mid-2018, UBS said.

Riesling Power, a company affiliated with The Blackstone Group, purchased Cayuga and the Somerset coal plant outside Buffalo — the only two operating coal-fired plants in the state — last year from a group of bondholders that had purchased them from the bankrupt AES Energy East in 2012. The sale came after New York regulators rejected a request to have ratepayers fund a $102 million conversion of the plant to natural gas. (See Cayuga Coal Plant in Jeopardy.)

The higher New York City prices suggested that 79 MW of uprates did not clear, but UBS said it expects prices to drop by $1/kW-month next year because of the uprates and exports from the Bayonne Energy Center, which is adding two new turbines that will boost its capacity from 512 MW to 644 MW. The New Jersey plant is connected to a substation in Brooklyn via a 345-kV transmission line under New York Harbor.

Additional downward pressure on New York capacity prices may come in the future from two new combined cycle gas turbine generators under construction, including the 1,100-MW Cricket Valley plant in Dover, expected to be operational by the first quarter of 2020.

The 650-MW CPV Valley plant has targeted a February 2018 opening, but construction has not yet begun on a 7.8-mile lateral to supply the plant. Millennium Pipeline sued the state Department of Environmental Conservation in December over the department’s refusal to issue a required water quality permit and expects a decision from the D.C. Circuit Court of Appeals in April or May. (See Pipeline Sues to Force NY to Issue Permit for CPV Plant.)

NYISO capacity auction hudson valley — | *NYISO*

One wild card is the 1,242-MW Roseton power plant in the Lower Hudson Valley, which has approval to export 500 MW to New England for the 2018/19 period. Roseton’s decision to export or not may depend on “whether a half year capacity obligation for the winter can be established to maximize its position in both markets,” UBS said. (See FERC Sides with ISO-NE in Capacity Dispute with NYISO.)

UBS said prices are unlikely to rise for the next three years. “With more renewables coming, it is hard to point to much of a bullish prospect on either energy or capacity until Indian Point retirements hit in 2020 and 2021,” it said in a March 23 report. (See NYISO, PSC: No Worries on Replacing Indian Point Capacity.)

The mothballed 435-MW Dunkirk coal-fired plant near Buffalo has “little chance” of converting to natural gas and returning to the grid, UBS said — a prediction that was strongly denied by NRG spokesman David Gaier.

“UBS doesn’t speak for NRG. Our plans are to move the gas addition project forward, as I’ve said several times since November,” Gaier said.

Impact on IPPs

The results were good news for NRG, for which NYISO represents 10% of its fossil-fueled generation. Two other independent power producers, Dynegy (4%) and Calpine (1%) have much lower exposures to the state.

NRG’s share price rose from $18.86 to $19.05 following the announcement of the results April 4, but the boost was short-lived and shares closed the week at $18.49.

April 10, 2017

MISO Begins Study on Declining Frequency Response

By Amanda Durish Cook

CARMEL, Ind. — MISO is beginning a study to assess its frequency response performance and identify needed improvements.

In the first half of 2017, MISO will compile system data from major generation loss events for evaluation. The RTO’s initial sample of generation loss events are spread evenly across the footprint, although it said data may not be available for some locations.

frequency response generation loss miso — | *MISO*

MISO’s frequency response continues to “decline year after year” and while not a pressing problem yet, it is “concerning,” Durgesh Manjure, MISO resource adequacy manager, said at an April 6 Reliability Subcommittee (RSC) meeting.

In January, the RTO’s staff asked for stakeholder input on how to address the declining frequency response capability, presenting preliminary simulations showing the system recovering too quickly when compared with real events — an indication of the need to fix governor parameters, officials said. (See MISO Aims for Improved Frequency Response Modeling.)

In the latter half of 2017, MISO will run simulations based on collected data and compare results to the actual events. By early 2018, the RTO will use stakeholder input to refine the study models.

Although MISO originally planned to use data from its SCADA system, it now says those measurements “seem inadequate for model validation” because the data are not detailed enough and not synchronized across locations, creating a potential time lag.

Data collected from phasor measurement units (PMUs) might be the better option, because their measurements are detailed and synchronized in real time across the grid, the RTO said.

However, Manjure said PMU data may not be available for all of the large generating units. In addition, PMU data is deleted after one year. It “remains to be seen how useful” the PMU data will be, Manjure said.

“Just being able to leverage the PMU data is a work stream in itself,” Manjure said. “We’re not quite sure which things are going to work … as we start peeling the onion.”

RSC Chair Tony Jankowski said he preferred MISO get the most detailed data to begin improving modeling.

Manjure said MISO would present more information on the study at the June RSC meeting.

April 10, 2017

Pseudo-Tie Feud Rises as Patton, NYISO Protest PJM Proposal

By Amanda Durish Cook

MISO’s Independent Market Monitor last week filed a complaint over PJM’s pseudo-tie procedure, the latest volley in an increasingly complex debate over the future of the pseudo-tie concept.

PJM NYISO pseudo-tie david patton — Patton | © *RTO Insider*

Spurred by a recent PJM bid to tighten its pseudo-tie rules, Monitor David Patton filed a Section 206 complaint April 6, claiming that the increasing use of pseudo-ties degrades reliability, hinders efficient dispatch and raises costs. He asked FERC to eliminate PJM’s existing pseudo-tie definition (EL17-62).

“PJM has asserted that it has a very broad right to impose requirements on external generators to ensure that their capacity can be delivered reliably and efficiently, but the PJM pseudo-tie practices exceed all reasonable bounds,” wrote Patton, whose Potomac Economics firm provides monitoring for MISO and NYISO.

NYISO also took issue with PJM’s March 9 FERC filing seeking approval to apply more stringent requirements on external capacity resources serving the RTO’s load. PJM wants the new rules to be effective in time for its May 10 Base Residual Auction (ER17-1138). (See PJM to Tighten Pseudo-Tie Rules Despite Stakeholder Pushback.)

In a March 31 protest, the ISO said PJM’s proposal — which would allow PJM to commit and dispatch generators directly interconnected to the New York Control Area — “could threaten the reliable operation of the NYCA and disrupt the NYISO-administered markets.”

Patton said PJM provides only “scant support” for its new, “arbitrary parameters,” and that the filing makes it “impossible for any supplier in MISO that does not currently have a unit pseudo-tied to PJM to meet these requirements to offer capacity in the [Reliability Pricing Model] forward auctions.”

If the new rules are implemented, PJM’s customers could experience annual capacity cost increases of $500 million to $4 billion, Patton said. The complaint suggested that FERC consider replacing pseudo-ties with a firm capacity delivery procedure, a collaborative approach that Patton and MISO presented last year. (See PJM Filing Renews MISO Monitor’s Call for Pseudo-Tie Elimination.)

PJM Cries Foul over MISO Pro Forma

Meanwhile, PJM and MISO are attempting to settle a disagreement over the Midwestern RTO’s stricter pseudo-tie pro forma agreement.

The two RTOs are considering adding coordinated pseudo-tie policies to their joint operating agreement “in lieu of MISO being a signatory to PJM’s agreement,” MISO Senior Director of Regional Operations David Zwergel said during an April 6 Reliability Subcommittee meeting.

Zwergel said the discussions are the result of PJM’s March 21 protest of MISO’s pro forma filing (ER17-1061).

“MISO made this filing without the opportunity for PJM to review, leaving PJM no choice but to file this protest and seek revisions to this agreement through the commission,” PJM wrote. It asked FERC to require MISO to “revise any provision of the proposed agreement to the extent it gives MISO unilateral authority to control the implementation, operation, suspension and/or termination of the impacted pseudo-tie, or is inconsistent with the coordinated implementation and operation of pseudo-ties as between MISO and PJM.”

PJM said it sought MISO input on the development of its own pro forma pseudo-tie agreement but was not granted the same courtesy.

Work Continues on Double-Counting Congestion

In a related matter, the two RTOs last week presented an update to their proposal for eliminating overlapping measurements of congestion related to pseudo-ties.

During an April 7 Joint and Common Market Initiative meeting, the RTOs proposed a revised solution that involves exchanging more congestion information in the day-ahead market and refunding or charging pseudo-tie owners for deviations between day-ahead predictions and real-time numbers.

“The RTOs will coordinate pseudo-tie firm flow entitlement impacts before the day-ahead run so that the congestion and the day-ahead LMPs for the pseudo-tie resources will better reflect actual congestion,” the RTOs said.

“We’d be aligning our firm flow entitlement impacts in the day-ahead to reflect what we think the settlement will be in real time,” said Kevin Vannoy, MISO director of forward operations planning.

PJM Interregional Coordination Manager Tim Horger said the solution solves the double-counting issue “as best we can” with prices more reflective of the real-time market. “It’s not going completely solve congestion, but we’re measuring that pseudo-tie impact on every coordinated market-to-market flowgate,” he said.

Horger said that the impacts will be brought “in front” of LMPs and pare down “excess congestion” that is usually folded into the pricing, reducing the need for refunds.

PJM and MISO staff have not yet determined which Tariff or JOA changes might be necessary, but Horger said pseudo-tied resources will not have to make any changes. Vannoy said MISO and PJM hope to adjust the market-to-market settlement process in time for a June 1 implementation.

A future phase of MISO and PJM’s solution will allow for optional scheduling and settlement of pseudo-tie transactions in the native balancing authority’s day-ahead market. In February, MISO and PJM said they would provide congestion rebates in the near term while developing a way to incorporate pseudo-ties in the day-ahead scheduling process by 2018. (See MISO, PJM Propose Solution to Pseudo-Tie Congestion Problem.)

April 7, 2017

Lifeline or Pipedream? EBA Panels Debate Need for More Gas in NE

By Rory D. Sweeney

WASHINGTON — More than three years and thousands of pages of analysis later, there is no consensus on how the electric industry should respond to the January 2014 cold snap that revealed weaknesses in the Eastern Interconnection.

The differences of opinion were on display during a panel discussion on gas-electric coordination at the Energy Bar Association’s annual conference on Monday.

Macdara Nash of National Grid and Todd Piczak of Kinder Morgan advocated for additional pipelines in the Northeast U.S., saying they would ensure sufficient gas supplies for generators on high-demand days. David Ismay of the Conservation Law Foundation called for peak shaving and increased gas storage, saying additional pipeline capacity would reduce utilization of existing infrastructure most of the time.

One thing all the panelists agreed on is that natural gas has a place in the region’s energy future and that action needs to be taken to better gird the grid against unforeseen events like the polar vortex.

“The region should be thinking about what are solutions, what can we do,” Nash said. “We think that natural gas is key.”

He cautioned that pipelines require an extensive lead time, “so if you believe in the problem [of potential pipeline capacity shortages], the time to act is sooner than later.”

Piczak said FERC has made progress on one half of the problem — ordering increased coordination between gas pipelines and gas-fired generators — but hasn’t done much to facilitate the other half, which is adding capacity. A major issue, he said, is the need for the commission to develop criteria other than long-term contracts to support a finding of public convenience and necessity.

Todd Piczak of Kinder Morgan speaks as fellow EBA Annual Meeting Gas-Electric Coordination Panelists Ismay (left) and Nash listen | © *RTO Insider*

Piczak’s company operates the Tennessee Gas Pipeline, one of the nation’s most critical natural gas conduits because it runs from Houston to Boston and crosses two prolific shale gas plays, the Utica and Marcellus in the region of Ohio, Pennsylvania and West Virginia.

Not a Capacity Problem

“This is fundamentally a regulatory problem,” he said. “There’s not enough gas for the generators when they need it. … It’s an important problem, and it’s a growing problem.”

Ismay said the issue isn’t the availability of gas — he said gas was never unavailable, even during the polar vortex — but that constraints and high demand make it prohibitively expensive. A new pipeline would, on average, be about half full half of the year and wouldn’t justify the installation costs, he said.

“Instead of a capacity problem … it’s a temporal, location-based problem of getting a certain amount of gas to a certain location … on the pipeline system at time of year,” he said. “We [will] always have days above the peak, even if we build a new pipeline.”

LNG storage has been and should be the solution, he said, along with demand response and energy efficiency to shave peak demand. He pointed out that while Massachusetts’ electricity rates are the fifth highest in the country, customers’ bills are the 31st lowest on average.

A study of future energy needs in the Bay State, conducted by Analysis Group for the state attorney general, found that, in a business-as-usual scenario, there will be no reliability concerns out to 2030, he said. Moving forward, energy storage, increased pipeline compression, additional pipeline loops and developing targeted markets will address remaining issues.

“If we understand the problem of temporal availability, let’s create a market for it,” Ismay said. “There is a role for natural gas in 2050, but it’s not very big. … It doesn’t run very much in the future.”

With natural gas already occupying 40% of installed generation and providing 50% of the electrons in New England, “our bridge is built” to a low-carbon future, Ismay said.

Discussion attendees pushed back on some of Ismay’s arguments, noting the Massachusetts study assumed best-case, “blue skies” scenarios and that adding localized LNG storage to gas-fired units raises their bid prices to levels comparable with coal-fired units.

“Another important thing to recognize about LNG solutions is you still have to get the gas from the LNG facility to where it’s needed,” Piczak said. “It’s not as easy as just to say, ‘Let’s put some LNG in a tank,’ and it’s going to be available.”

NRDC, J.P. Morgan Skeptical of Pipeline Need

At the EBA’s general session on Tuesday, J.P. Morgan’s Ian C. Connor, and David Doniger of the Natural Resources Defense Council, also expressed skepticism over the need for additional pipelines.

Connor, global co-head of J.P. Morgan’s power & utility group, noted that renewables are supplanting a lot of retired coal capacity.

“I think you’re going to see significantly less gas [generation] build than people believe,” he said. “These [combined cycle gas turbines]: Yes there are a few being built between now and 2020. After 2020, right now no one really thinks any more CCGTs are getting built. So how many more pipelines are you really going to need to build? I think it’s a lot less.”

Doniger, director of NRDC’s Climate & Clean Air program, said the rise of renewables and flat electric demand should prompt FERC to look more skeptically at the need for new pipelines.

“Are we building gas pipelines in order to stimulate the development of new gas power plants or is there really a need?” Doniger asked. “If you look at the system more systematically … efficiency, renewables and some of the other options can [replace] extensions of the gas pipelines and the natural gas infrastructure. The FERC process for evaluating new pipeline applications doesn’t ask all those questions and [it] should.”

Rich Heidorn Jr. contributed to this article.