Page 1278 – RTO Insider

July 3, 2017

SPP, Peak Reliability Pitch RC Services for Mountain West

By Tom Kleckner

DENVER — SPP and Peak Reliability extolled their virtues as reliability coordinators (RCs) before the Colorado Public Utilities Commission last week in a bid to provide the reliability function for the Mountain West Transmission Group.

Peak Reliability is Mountain West’s current RC. SPP would include the RC function among the bundled services it would provide Mountain West, should the informal collaboration of Western utilities eventually become members of the RTO. (See Mountain West, SPP Tout RTO Membership to Colo. PUC.)

SPP peak reliability mountain west — Interested parties gather in Colorado PUC’s hearing room. | © *RTO Insider*

The courtship is leaving the Colorado PUC a little queasy.

“This is like if your child potentially dates, if not marries, the wrong person,” Chairman Jeff Ackermann said in wrapping up the information session. “Take that wherever you want to go, but ultimately, consenting adults do what consenting adults want to do.”

“We may not want to pay for the wedding,” Commissioner Frances Koncilja pointed out.

Mountain West — comprising eight investor-owned utilities, municipalities, generation and transmission cooperatives, federal power marketing administration projects, and their subsidiaries — announced in January that it was beginning discussions with SPP about potentially joining the RTO. The group expects to arrive at a decision by October.

However, Koncilja prodded a panel of Mountain West representatives as to when the commission would see financial numbers coming out of the negotiations with SPP.

“I share your sense of urgency,” said Steve Beuning, director of market operations for Mountain West member Xcel Energy, offering no further response.

The Market Provides

Peak Reliability currently provides only RC services to Mountain West for about 5 cents an hour, CEO Marie Jordan said.

If SPP is to assume RC responsibilities for Mountain West, its members “would continue to pay what they pay Peak now,” according to SPP COO Carl Monroe.

“What they save is anything they would have to do if we were not the RC,” Monroe said, reminding the commission that SPP would also likely be running the balancing authority and the markets, besides other functions. “I know when we have to provide the functions we provide, we can do it more cost-effectively and more reliably than if we [were just the RC].”

Monroe said SPP’s “first line of defense” against reliability concerns is to let the market take action by resolving binding constraints through economic dispatch, which uses the lowest-cost generation facilities to meet consumer demand while recognizing any operational limits.

“The market itself provides you that mechanism. The market, for us, is a tool to maintain enhanced reliability,” he said.

Beuning pointed out that economic dispatch is “the missing piece in our tool kit.” The Western Electricity Coordinating Council, which has served as the Western Interconnection’s Regional Entity since 2007, has yet to implement economic dispatch. Peak was spun off as an independent RC from the WECC in 2014.

Economic dispatch “is the one thing that comes along with being a market operator,” Beuning said. “It’s my belief and opinion that at this point, we could obtain an integrated service at a lower cost for our customers, instead of paying for RC services or paying the Peak.”

Colorado PUC’s Frances Koncilja, Black Hills Power’s Denton McGregor | © *RTO Insider*

“It would be a lost opportunity cost for us to not bundle those services together,” said Denton McGregor, reliability center manager for Mountain West member Black Hills Power.

Status Quo — or No

Jordan touted Peak’s experience as Mountain West’s incumbent RC and the knowledge it has gained providing the same service for the Western Interconnection. She said Peak continuing as the region’s single RC would address reliability concerns caused by the continued addition of renewable and intermittent resources, and it would provide a “single, unbiased” entity focused exclusively on reliability coordination.

Monroe, PUC Commissioner Frances Koncilja and Jordan listen to question from Kara Brighton Fornstrom, Wyoming PSC’s deputy chair. | © *RTO Insider*

“A single RC has been a very important piece of the vision for reliability in the West,” Jordan said. “The biggest concern is how the interconnection continues to bring on [renewables]. I also don’t want to underestimate how knowledge grows … we’re mature in our tools, we’re mature in our sophistication and we have learned. Based on feedback I get from our funding members, our model is becoming so much more reliable for them, from the time we started … to where we are today. It’s been tremendous growth.”

A nonprofit organization like SPP, Peak is responsible for an area of 1.6 million square miles that includes all or parts of 14 western states, Canada’s British Columbia and the northern portion of Baja California, Mexico. It oversees more than 110,000 miles of transmission lines, with centers in Vancouver, Wash., and Loveland, Colo.

For his part, Monroe played up SPP’s experience as both an RC and a market operator, underscoring the understanding the RTO gained integrating RC services in the Western Interconnection with the 2015 addition of the Integrated System. (See Integrated System to Join SPP Market Oct. 1.)

“Reliability for us is job [No.] 1,” he said. “When we’ve added things, we’ve done so in a manner that protects reliability or enhances reliability. Part of the benefits Mountain West is looking to get are those benefits at a cheaper cost to the consumers themselves. Everything we do is designed to enhance reliability at a cheaper cost.”

WECC CEO Jim Robb said costs would likely increase for Mountain West members should SPP become their RC.

“The cost of providing RC services isn’t particularly scalable,” he said. “I can’t see Peak’s cost structure changed, but it seems to me the pressures in aggregate go up. How they are allocated among customers remains to be seen.”

And that’s an issue for the Colorado PUC.

“We’re concerned about how these costs roll out and which ones end up back here in this room at some point in the future,” Ackermann said.

Colorado PUC Chairman Jeff Ackermann questions Tri-State’s Mary Ann Zehr, Xcel Energy’s Steve Beuning. | © *RTO Insider*

Monroe said SPP would incur additional costs should it separate the RC function from the market and balancing authority functions. He said there is a benefit to having multiple RCs in an interconnection, as evidenced by the 13 RCs in the Eastern Interconnection.

“We think [multiple RCs] reduces risk because now you have two different organizations and two different systems looking over that whole area,” he said. “In the East, we reduce the risk because we have people helping us do that. We’ve never been in an environment where we weren’t coordinating with other parties.”

Negative Consequences

Losing Mountain West would cost Peak — which has operated with a $44.6 million budget for each of the last two years — about 10% of its load.

“It’s negative to the interconnection, [and] it’s negative to area reliability — and not just for the Mountain West,” Jordan told RTO Insider. “We’ve taken full responsibility to keep this grid functioning reliably, and that’s a consensus shared by our members.”

The PUC has tentatively scheduled a third information session on Mountain West’s proposal to join SPP. The Aug. 24 session will focus on governance issues.

SPP will be holding its leadership meetings at the Colorado Convention Center and a nearby hotel in Denver next month. As he did during the PUC’s first information session in March, Monroe invited those in the room to attend the meetings and see how the RTO governs itself. He said SPP set aside 190 seats for the July 11-12 Markets and Operations Policy Committee meeting, with 170 attendees having already registered.

July 3, 2017

SPP Briefs: Week of June 28

SPP stakeholders last week spent two hours discussing the need for a high-priority congestion study in the Texas Panhandle, only to determine that more discussion is needed.

The Strategic Planning Committee scheduled the two-hour conference call June 26 to review the study’s scope and its scenarios. Despite stakeholder suggestions to relitigate the requirement for the study and consider alternative study methods, SPC Chair Mike Wise successfully kept the group on task.

“These other issues are part [of the discussion] but very tangential,” said Wise, senior vice president of regulatory and market strategy for Golden Spread Electric Cooperative. “We can have a fuller discussion at the next SPC meeting.”

The committee added time to its July 13 face-to-face meeting in Denver, following a two-day Markets and Operations Policy Committee meeting. Members plan to discuss a suggestion by American Electric Power’s Richard Ross that the congestion study evaluate confirmed service and unfilled hedges.

SPP’s Board of Directors directed staff in April to conduct the high-priority study after it canceled a 345-kV transmission project in the area. Chairman Jim Eckelberger agreed the study should take a systemwide look at congestion caused by the proliferation of wind farms. (See SPP Board Cancels Panhandle Line, Seeks New Congestion Study.)

“I’d rather take a little more extra time and do it right, rather than punch on,” SPP Director Larry Altenbaumer said. “I appreciate the complexity of issues out there, but we have to decide how best to deal with the continued growth of wind in our footprint.”

Staff is currently analyzing the saturation point for renewables sinking within SPP to determine at what point the additional generation would “no longer be economic,” SPP Director of Engineering Antoine Lucas said.

“Until then, continue to expect additional requests and more renewables added to the system,” he said. “Renewables are now replacing other renewables at similar price points.”

“This wind is coming on,” the Wind Coalition’s Steve Gaw said. “It doesn’t make sense to not consider its impact on the system. The potential benefits shouldn’t be ignored.”

The SPC did not come to an agreement on the study scenarios. Staff is recommending developing three scenarios from the five thresholds for interconnection costs of renewable energy, ranging up to $100,000/MW. SPP says the previous 7.6 GW of wind placed in service had an average cost of $32,500/MW. Connecting the total studied capacity of 43.3 GW would cost more than $1 million/MW to in part account for needed investment in new transmission infrastructure.

SPP Vice President of Engineering Lanny Nickell said staff is looking at known constraints, rather than future generation, to ease its workload. He said 5.5 GW of wind projects have interconnection agreements and are meeting their milestones.

During the weekend before the call, SPP members Empire District Electric, Kansas City Power & Light, Oklahoma Gas & Electric, Southwestern Public Service and Westar Energy submitted a letter to the SPC and the board’s Members Committee, questioning the value of the study. Signatories said previous staff analysis of congestion in the area showed a benefit only when the models included “extraordinarily high levels of wind.” They said SPP’s next 10-year assessment of transmission needs would “provide a comprehensive solution for the region.”

“We are concerned that a special high-priority study will circumvent the generator interconnection and aggregate study processes that are used to identify cost-causers and the assignment of costs,” the letter said.

Z2 Task Force Suggests its own Retirement

The Z2 Task Force will this month recommend to SPP leadership and stakeholders two alternatives for assigning financial credits and obligations for sponsored transmission upgrades under Attachment Z2 of the RTO’s Tariff.

The group also agreed during its June 27 meeting in Dallas to let its charter expire at the end of July, unless otherwise directed by the board or MOPC.

The group has spent its last few meetings discussing the pros and cons of the two staff-suggested alternatives: granting Z2 credits only to upgrades that increase transfer capability and creating credit payment obligations under a Tariff schedule. (See SPP Members Send Z2 Alternatives to MOPC.)

SPP strategic planning committee — Buffington | © *RTO Insider*

Task force Chair Denise Buffington, corporate counsel at KCP&L, said she was disappointed the group was “unable to accomplish more.”

“It seems impossible to get folks to pull away from current parochial impacts to focus on the underlying policy decision: Do we want to socialize or subsidize these types of projects, or provide a market mechanism?” Buffington said. “There is no sense beating a dead horse. There is no support for it at this time.”

MMU: Wind Generation up, Coal Production down

SPP wind generation continues to increase at the expense of coal, the RTO’s Market Monitoring Unit said.

Wind accounted for 28% of all energy produced in SPP’s market this spring, up from 22% in 2016 and 15% in 2015. Coal’s share of output has meanwhile dropped to 40%, down from 57% just two years ago.

SPP recorded a North American RTO-high for wind penetration on March 19, when wind accounted for 54.2% of the market’s energy production.

The MMU’s State of the Market report, covering the months of March, April and May, also revealed that rising gas prices have led to a corresponding increase in LMPs.

Gas prices at the Panhandle hub have averaged $2.70/MMBtu this spring, compared to $1.68/MMBtu last year. At the same time, average real-time LMPs increased from $17.07/MWh to $23.48/MWh, while day-ahead prices rose from $17.37/MWh to $23.47/MWh.

— Tom Kleckner

July 3, 2017

Renewables Reshaping NY Grid, Policy

By Michael Kuser

POUGHKEEPSIE, N.Y. — While renewable resources currently have only a limited impact on the New York grid, that’s set to change as the state advances on its clean energy goals, industry experts said at a conference last week.

The amount of solar in NYISO’s interconnection queue has nearly doubled within the past three months — from 850 MW to 1,600 MW, CEO Brad Jones said at the Renewable Energy Conference. The Business Council of New York State and the Hudson Renewable Energy Institute hosted the June 28 event at Marist College.

Solar and wind together now account for around 5% of the state’s generation, compared with a 20% share for hydropower. That “5% piece of the pie has to grow incredibly, by as much as five times what it is today,” to reach the state’s Clean Energy Standard goal of having 50% of generation derived from renewable resources by 2030, Jones said.

“On the wind side, we’ve got 3,300 MW of wind in our queue, and that’s not including whatever the state may do with offshore wind,” he added. Gov. Andrew Cuomo earlier this year set a target of building 2,400 MW of offshore wind capacity by 2030.

NYISO renewable energy conference new york renewables — Marist College on the Hudson River | © *RTO Insider*

The Marist campus on the Hudson River sits in the middle of Central Hudson Gas & Electric’s service area. The utility serves only 3% of the state’s load but leads the state in terms of photovoltaic integration.

“We have over 6,000 [solar] installations interconnected to the grid today … about 66 MW,” Paul Haering, Central Hudson senior vice president of engineering, said during a presentation. “So while you think that would have a dramatic impact in terms of our peak load, the reality is, when the sun shines is not when everyone’s turning their air conditioners on and coming home from work.”

Maximum summer demand for the utility typically occurs at 7 or 8 p.m. The mismatch between PV output and peak usage represents a challenge for how to integrate distributed energy resources while minimizing the need for new transmission infrastructure, according to Haering.

“But if I’m going to replace assets, I replace it with current standards,” Haering said. “That means larger wire size and higher-voltage circuits that help us to integrate more PV, which gives me better thermal and voltage profiles in order to be able to support the integration of more PV on the system.”

And Central Hudson is adapting the grid to DERs through enhanced intelligence of the distribution grid itself rather than smart meters.

“We have technology now that allows for bidirectional flow of power on the system,” Haering said. “We built the grid for one-way power flows, so now with power coming the other way, we use bidirectional regulators and switch capacitators and substation path changers that have the capability to sense bidirectional flow and respond accordingly.”

In the past two years, National Grid has interconnected more solar than gas-fired generation in New York, said Melanie Littlejohn, the utility’s vice president of community and customer management for the state. That trend motivated National Grid to invest $100 million in Sunrun, the nation’s largest residential solar company. Storage is a key part of Sunrun’s portfolio, Littlejohn noted. (See NY Bill Sets Stage for Storage Targets.)

Littlejohn also pointed out that the North Country region has the most electric vehicles in Upstate New York, prompting the utility to install 68 charging stations in downtown Syracuse, in partnership with the federally supported Clean Cities coalition, which runs the utility’s stations throughout the state.

Who Pays?

Asked how National Grid manages the effect of renewable energy programs on customer rates, Littlejohn said, “Very gently. … More than 30% of our Upstate New York customer base lives at or below the poverty level.”

Tina Palmero, deputy director of the state’s Office of Clean Energy, said the New York State Energy and Research Development Agency is working to meet the governor’s ambitious offshore wind target by 2030: “And of course we have to think of rate impacts as well.”

One option for controlling costs could entail increased financial support for existing nonemitting resources. Regulators are looking at the operations of so-called Tier II generators, which consist mostly of small hydropower facilities, many of them family-run. “If it’s cheaper to keep them open than seeing them cease operation and having to procure new renewables, the commission will look at that and consider whether or not they should get some additional subsidy,” Palermo said.

Diane Burman of the New York Public Service Commission said that providing the best possible electric service to customers “is what it’s all about.”

Burman, who was recently confirmed for a second six-year term as commission, said she hopes to re-examine what the PSC can do in “giving the flexibility to others, so that we are not dictating the technology, maybe even the brand that should be used. That’s not helpful.”

July 3, 2017

ERCOT Briefs: Week of June 28

Sweltering temperatures led to three new ERCOT demand records in quick succession during June. The ISO has set eight highs for monthly demand during the last 12 months.

The Texas grid operator recorded consecutive peaks of 66.7 GW, 67.5 GW and 67.7 GW during the afternoon of June 23. The final number, and new record, came during the 4 p.m. hour, breaking the previous record of 66.5 GW set in June 2012.

ERCOT operators monitor the Texas grid. | © *RTO Insider*

ERCOT has projected a new all-time demand peak of nearly 73 GW this summer. The current record of 71.1 GW was set last August. (See ERCOT Sees Enough Generation Through 2022, 73-GW Peak for Summer.)

TAC Approves Revision Requests in Email Vote

ERCOT stakeholders unanimously approved a pair of revision requests in an email vote last week, following the earlier cancellation of the monthly scheduled Technical Advisory Committee meeting.

Both changes were approved by 22-0 margins. The TAC has 30 voting members.

NOGRR170: Revises the Nodal Operating Guide to be consistent with NPRR824 language related to NERC Reliability Standards EOP-011-1 (Emergency Operations) and BAL-001-2 (Real Power Balancing Control Performance).
RRGRR014: Conforms the Resource Registration glossary to the as-built release, which captured baseline updates before the approvals of RRGRR006 and RRGRR007. Adds solar resource registration inputs omitted from the greybox tab for RRGRR009.

— Tom Kleckner

July 3, 2017

Better DER Approach Needed, Calif. Agencies Told

By Jason Fordney

The growth of distributed energy resources on the California grid will require new approaches and better coordination between system operators to avoid problems, state officials heard last week at a California Energy Commission workshop.

Representatives from utilities, DER companies and others advised members of the CEC and the California Public Utilities Commission on the various issues related to integration of new technology onto the electric grid.

The grid is becoming more decentralized, and the amount of DERs — including rooftop solar, energy storage and a host of other technologies — is expected to grow significantly in California in the next three to five years. Fleshing out communication methods between transmission operators, distribution utilities, DER providers and CAISO is one of the biggest tasks associated with incorporating the new systems.

CAISO distributed energy resources energy storage DER — The Amount of DER Including Rooftop Solar is Projected To Keep Growing

DER companies are trying to open new markets at various points in the electricity delivery system, including selling to utilities and retail customers, as well as through development of market mechanisms at CAISO. The ISO wants to enable that process to help balance output from renewables, and next month will present its Board of Governors with a suite of related new rules stemming from its Energy Storage and Distributed Energy Resources (ESDER) Phase 2 initiative. (See CAISO Finalizes Rules for DR, Distributed Generation.)

Distribution system operators (DSOs) should be able to advise DER providers and communicate with them on grid integration and operational issues, Pacific Gas and Electric Director of Integrated Grid Planning Mark Esguerra said. CAISO should also provide day-ahead DER schedules to DSOs, as well as develop a pro forma DER integration agreement.

The ISO often dispatches DERs without knowing if they are feasible on the distribution system and when there is little visibility on their effect on load and the transmission-distribution interface, Esguerra said. DERs are different from demand response and energy efficiency resources because distributed energy is not an absence of load, but rather additional energy being put into the system that must be managed.

Tesla Business Development Manager Damon Franz said DERs can mitigate the effects of energy infrastructure on water and the environment. He also argued they provide a wide range of services, including backup power, lowering energy costs and managing the intermittency of renewables.

Franz highlighted the importance of data on what needs DERs can satisfy. He requested that permitting be made easier and said interconnection for energy storage “should be no more complicated than simply deploying a device.”

But Jim Baak, program director at Vote Solar, noted that California utilities are being asked or required to forego capital investment in favor of DERs, which might not be in the interest of their shareholders. There should be a wider focus beyond policies and process changes, and state policy objectives should align with financial goals of stakeholders, he said. There are also concerns about overinvestment in DERs in the wrong locations.

“My concern is the vision is somewhat myopic,” he said. “What we really hope to achieve with distributed resources is to achieve policy goals.”

James Barner, resource planning engineer with the Los Angeles Department of Water and Power (LADWP), said that without an engaged interconnection process, DERs will affect reliability, including the problem of overgeneration at certain times. The utility plans to have 1,500 MW of distributed solar in the next 15 years, but DERs do create new problems on the system, he said, and rooftop and carport solar cannot be curtailed.

LADWP recognizes that DERs “add a lot of diversity to our renewables portfolio,” he said. Renewables represented 21% of the utility’s portfolio in 2016, but that is expected to grow to 65% by 2036. The utility plans to soon issue a Distributed Energy Resources Integration Study.

The CEC on June 14 issued a white paper on Coordination of Transmission and Distribution Operations in High Distributed Energy Resource Electric Grid that lays out the schedule and goals for integrating DERs. The agency said its next Strategic Transmission Investment Plan will include information and data on distributed generation.

July 3, 2017

Panel: NY Renewables Require Clear Regulations

By Michael Kuser

POUGHKEEPSIE, N.Y. — New York’s push to derive half its electricity from clean energy by 2030 must be accompanied by regulatory consistency to develop the necessary resources, panelists said at an energy forum last week.

State regulatory policy contains inherent conflicts that hinder renewable development, Paul DeCotis, senior director of energy and utilities at West Monroe Partners, said during the June 28 Renewable Energy Conference, hosted by the Business Council of New York State and the Hudson Renewable Energy Institute at Marist College.

DeCotis, who formerly served as energy secretary and chair of the state energy planning board for two New York governors, led a panel on regulatory structure.

Speaking about Long Island solar projects unlikely to be built because they’re proposed for green space, DeCotis said, “It goes against the policy of the state of New York on the one hand, in terms of renewable energy development, but it supports other green space initiatives. There’s always going to be an inherent policy conflict, which makes these goals even more difficult to attain. So it does take some certainty of regulatory environment, and it takes time.”

DeCotis noted that he and fellow panelist Paul Curran — managing partner of BQ Energy, a Poughkeepsie-based developer of wind and solar projects on brownfield sites — started talking about the state’s need for additional transmission infrastructure investments in 2007. Those projects are likely to come online in 2020.

“That’s 13 years for transmission to be built,” DeCotis said.

Consistency is Key

“I can play by any rules … but to the extent that the rules keep changing, it gets very difficult,” Curran said. “From a regulatory point of view, we love consistency.”

Renewable Energy Conference attendees | © *RTO Insider*

Regarding the troubled solar projects on Long Island, Curran said green space is the wrong location for renewable energy.

“There’s landfills all over the place; there’s brownfields all over the place — that’s the right place,” he said.

BQ didn’t build any transmission lines at the 35-MW wind farm it constructed in Buffalo. The developer spent just $1 to buy disused substations from a shuttered steel plant that used to draw 300 MW.

“We do the same thing with landfills,” Curran said. “There’s five or six landfills in the middle of New York City, nothing else can be done with them … but the closer we get to load centers, New York City, Boston, etc., the more people like Central Hudson [Gas & Electric] value the electricity,” adding that NYISO also recognizes the value of siting generation closer to where it’s consumed.

Regulators Look to Performance

David Pacyna, CEO of North American T&D Group, said that when he talks to utilities about buying technology, “the concept of interconnecting renewables to make the utility assets perform properly under those scenarios of intermittency and so forth are, if not at the top of the list, very close to it.”

NATDG is a private equity fund that buys into technology service providers that sell to utilities in the U.S. and around the world. Prior to working for the company, Pacyna spent 30 years with Westinghouse Electric and Siemens and supervised construction of the Neptune project connecting Long Island with PJM, the Hudson transmission project and the Trans Bay Cable under San Francisco Bay.

“What does take it in hardware and software to make those rules that frustrate all but actually result in electricity coming out of the light socket?” asked Pacyna. “There’s a growing recognition [by regulators] of the need to invest in the grid.”

On rate designs, Pacyna said regulators in states such as Missouri and Illinois are starting to ask how they can best structure rates to incentivize investment in both grid modernization versus the grid of the future.

“Regulators also are asking how they can use performance-based rates to support investment in distributed energy and renewable resources,” he said.

Lack of a Trump Effect

Ray Wuslich, partner at Winston & Strawn, thought it would be easy to make a presentation in Poughkeepsie about the impact of the Trump administration on the power industry. But when he looked at President Trump’s energy policies, he found “there wasn’t much to go on.”

“We haven’t had any big ideas in the energy space, in energy policy, in over 25 years … really going back to the 1980s when FERC and Congress started looking at competition on the natural gas side and unbundling supplies from the pipeline transportation business,” Wuslich said. “It was crystalized in the Energy Policy Act of 1992 … and everything we’ve been doing since then has been evolutions of that.”

Former President Barack Obama pushed EPA’s Clean Power Plan, which Trump made a campaign issue for its impact on the coal industry, Wuslich noted. Now that Trump has called for repeal of the CPP, which may take up to five years to achieve, “the question is, can the repeal of that rule really save the coal industry and resurrect coal-fired generation?”

Wuslich cited the obstacles facing coal: economics (that is, cheaper, more efficient natural gas); an aging coal fleet; unfavorable state policies; renewable portfolio standards in 29 states and D.C.; major corporations that are focusing on sustainability and clean energy; and the apathy of utility executives, who are not rushing out to build new coal plants.

He noted that a recent Energy Information Administration report said repeal of the CPP could boost the prospects for coal.

“But does this make sense? Does this reflect reality, given where we are in the marketplace?” Wuslich asked. “There’s hardly a week goes by where you don’t see another blurb in the trade press that so and so is going to shut down 500 MW of coal, or 300 or 1,500 or whatever. It’s just a constant drip of these plants retiring, and that’s because of the market.”

July 3, 2017

PSEG, Dynegy CEOs Provide Clashing RXs for Market Woes

By Rory D. Sweeney

HERSHEY, Pa. — Attendees at last week’s Mid-Atlantic Conference of Regulatory Utilities Commissioners conference heard strikingly different prescriptions for how to fix the wholesale energy markets from the CEOs of New Jersey utility Public Service Enterprise Group and independent power producer Dynegy.

In a presentation Monday, PSEG CEO and Chairman Ralph Izzo argued that there’s a “missing money problem” among non-emitting generators. While net-metered residential solar generators are paid a premium of up to $415/MWh for being emissions-free in New Jersey, nuclear units receive no premium for having the same attribute and are paid PJM’s clearing price in their zone.

“We believe that wholesale power markets are experiencing some basic failures,” he said.

PSEG operates the Salem and Hope Creek nuclear plants in New Jersey and is a part owner of the Peach Bottom nuclear plant in Pennsylvania. With low-cost natural gas and subsidized renewables keeping energy prices low, owners of nuclear plants say the facilities are losing money and might be closed unless the states where they’re located cough up zero-emissions premiums for them as well. Such discussions are ongoing in Ohio, Pennsylvania, New Jersey and Connecticut. So far, only Exelon has been successful in securing credits for its units in Illinois and New York.

Left to right Drexler, Liz Burdock of the Business Network for Offshore Wind, Treseder, Thumma, Melnyk and moderator NJ BPU Commissioner Joe Fiordaliso | © *RTO Insider*

Izzo also called for changing customers’ bills to ensure that they see the premium they’re paying for solar. Customers of PSEG’s utility arm, Public Service Electric and Gas, have indicated that they’re unwilling to pay more than $5/month for additional renewable energy, but they’re already paying this much and aren’t aware of it because “we don’t tell them,” he said.

“Over the last three years, New Jerseyans have paid over $400 million a year for renewable energy credits, producing less than 2% of the in-state electricity,” he said. “I think that they are deserving of a transparent conversation on matters such as that, and I would be the first to champion the continued payment of that, but they are deserving of knowing about it.”

macruc dynegy pseg — Flexon | © *RTO Insider*

Dynegy CEO Robert Flexon stressed the favorable economics of his mainly coal- and gas-fired merchant generation fleet. He argued that subsidies for uneconomic units create a “subsidy death spiral” that pushes other units into becoming uneconomic and seeking a subsidy of their own. The result is a dismantling of the market’s basic function to procure energy at the lowest possible cost.

“That’s kinda what we signed up for,” he said.

Flexon argued that “utilities have a different DNA than a merchant generator” in that they are “leaning heavily on their core competency of dealing with the politics — which the [independent power producers] aren’t nearly as good at — and working special deals that upset the flow of the marketplace.”

When utilities are losing money, they go to governments for help, he said.

“You need to help yourself,” he said. “What I think is the biggest threat to reliability is the lack of coordination between the states and PJM, and the states doing things to take the economic generators and push them to the side.”

Dynegy originally sought a bailout for its Illinois coal units while Exelon was seeking the one it ultimately received for its nuclear units. When state support became unlikely, Dynegy pivoted to fight the zero-emissions credits (ZECs), joining a federal lawsuit challenging the state’s action.

Flexon called on regulators to require utilities to “match” any subsidies they receive with equal reductions to their annual dividend distribution. He cited FirstEnergy receiving an annual $250 million distribution modernization rider in Ohio while it distributes $600 million in annual dividends. He said it is unfair for Exelon to receive millions in ZECs over the next 12 years for five of its nuclear plants when it is able to pay $1.1 billion in dividends.

“I would say to the regulators, if you’re going to give them the money, you ought to look to their dividend,” he said. “If you want to shore up the balance sheet, I need the company match.”

In a panel discussion focused on wind energy, panelists also blamed utilities for artificially stalling market forces, but they defended renewable subsidies.

“The electric utility industry is an industry made of large institutions, and these large institutions have billions of dollars invested in assets that they own and operate, so my concern is that [they believe] renewable energy is a threat to the existing [way] of doing business,” said Markian Melnyk, president of Atlantic Wind Connection.

He referenced the assertions by Izzo and Flexon that the renewable sector is subsidized and “undercuts” their business. “My concern is that the federal government would hear that message and then take action to try to limit the advancement of renewable energy,” he said.

Avangrid’s Eric Thumma also defended existing pathways for renewables development, such as state renewable portfolio standards, joking that “it’s hard to take my blankie and my teddy bear away from me.”

State goals have proven effective, he said. “We know the RPS works. We know that it gets projects built.”

Beth Treseder of DONG Energy agreed. “We, too, are primarily looking to the states for leadership,” she said, but added that her company is also investigating how it can “take advantage” of the current federal focus on infrastructure development to improve critical ports and transmission lines.

For states themselves, the push to meet constituent demand for both cheap and environmentally conscious power means focusing on both costs and results.

“We’re balancing the economic and the environmental in our state,” Delaware Public Service Commissioner Kim Drexler said. “In my opinion, we’re really looking at the least expensive way to meet those requirements.”

July 3, 2017

Analysts Provide Insight into Wall Street Perspective at MACRUC

By Rory D. Sweeney

HERSHEY, Pa. — A panel of financial analysts at last week’s Mid-Atlantic Conference of Regulatory Utilities Commissioners conference peeled back the curtain on elements of their decision-making that can sometimes infuriate energy company executives and state officials alike.

MACRUC financial analysts wall street — Left to right Ritter, Ianno, Doerr, Fleishman and moderator Burman | © *RTO Insider*

The moderator, Diane Burman of the New York Public Service Commission, set the tone for the discussion by recounting her earliest memory of Wall Street workers. Her mother had warned her never to speak to them — a message that was reaffirmed when she joined the commission.

“The financial health of our energy industry is extremely, extremely important,” she said. “As commissioners, we struggle with what that means, and with what we do … good, bad or indifferent.”

The panel assured the audience that regulators have a major influence over how utilities are viewed by the financial sector. “We pretty much watch everything you do,” said Steve Fleishman of Wolfe Research. “We also care about how you communicate why you’re doing it.”

Analysts’ perception of the relationship between utilities and their regulators is the “primary driver of credit ratings,” said Lesley Ritter of Moody’s Investor Services.

Heike Doerr of S&P Global Market Intelligence said that one of the things that lowers ratings of commissions is inconsistency and uncertainty. Political influence tends to be a negative factor, she said.

One of the reasons why is because continuity can’t always be anticipated from state to state. “Ideally, we’d do things on a national-policy basis,” said Anthony Ianno of Morgan Stanley.

Fleishman noted another issue with a diminished federal vision.

“We’re moving into clearly ‘all of the above’ territory, and the one risk of that is it could get expensive,” he said, referring to recent moves by state legislatures to financially prop up certain types of generating resources. “If you support ‘all of the above,’ that means we’re paying for ‘all of the above.’”

He warned that “it’s crunch time” for states to determine which resources are most important to them.

“If states really have a view that they want to preserve nuclear or they want to preserve coal, they’re going to have to make that call relatively soon. … Now’s the time to make it clear what you’re trying to do,” he said. “There just needs to be an understanding that there’s costs to it, and there could be downsides to market functioning. … Maybe there’ll be a chance to do it in a more coordinated manner that keeps the functioning of markets in place.

“If we don’t figure this out,” Ianno warned, “what will end up happening is that those who can afford it will disaggregate from the grid, and the rest of the ratepayers will absorb all of the costs associated with the grid, and that’s a broken model.”

Doerr explained that her company’s state rankings are far more dynamic than might be expected. “It’s not just if your state is making improvement; it’s the pace at which improvement is coming relative to other states,” she said. “Many of you have companies operating in your jurisdictions that operate in other states, so the pipe needs to be upgraded everywhere.”

Analysts also complained about “black box” rate settlements that don’t provide any clarity on details like rate base or return on capital.

“If the law doesn’t allow it, why not change the law so there’s more transparency?” Ianno asked.

July 3, 2017

NextEra-Oncor Deal Meets Third Denial

By Tom Kleckner

Texas regulators last week again refused to revisit their decision to reject NextEra Energy’s proposed acquisition of Oncor, the state’s largest regulated utility.

The ruling by the Public Utility Commission of Texas came just two days after Florida-based NextEra filed a 57-page request for rehearing. Commissioners Ken Anderson and Brandy Marty Marquez responded to the motion during a June 29 open meeting.

“It is time to bring this chapter in the [Energy Future Holdings] bankruptcy to a close and consider other options more suitable to Oncor and its ratepayers, as well as ERCOT and its market participants,” Anderson wrote in a memo.

The commission rejected NextEra’s $18.7 bid for Oncor in April, finding it not to be in the public interest. (See Texas Commission Denies NextEra’s Bid for Oncor.)

Anderson said he remained unpersuaded “by [NextEra’s] regurgitation of essentially the same arguments” made in a previous rehearing request. He noted that “almost every intervenor” in the docket (No. 46238) supported the commission’s original decision and urged the PUC to deny the request.

Marquez concurred with Anderson’s memo during a discussion that lasted 30 seconds.

NextEra did not respond to a request for comment on its next steps following the decision. The company has for years eyed the purchase of Oncor, the lone successful business of bankrupt EFH. Proceeds from the sale would have been spread among EFH’s creditors, who last year reached a settlement to end a bankruptcy first declared in 2014.

NextEra filed its latest request for a rehearing June 27, arguing that the PUC overstepped its authority, ignored evidence, misinterpreted Texas laws and used bad judgment when it shot down the acquisition.

The company contended that the PUC’s opinion “constitutes arbitrary and capricious decision-making and an abuse of the commission’s discretion.” The commission’s final order contained 14 errors of law, NextEra said, and it intends to “preserve the company’s rights to judicial review.”

“The commission must determine whether a proposal to ‘change the ownership of the largest utility in Texas is in the public interest’ or whether the public interest is better served by leaving the state’s largest utility under the constraints of ownership by financial investors mired in bankruptcy,” the company said in its petition.

The commission turned down NextEra’s first request for a rehearing early last month. (See Texas PUC Again Rejects NextEra’s Oncor Bid.)

The PUC continues to operate with two commissioners while it waits on a replacement for former Chair Donna Nelson, who left the commission in May. Texas Gov. Greg Abbott is not expected to name Nelson’s successor until the end of the upcoming special legislative session, which begins July 18 and could last up to 30 days. (See Texas PUC Chair Nelson Stepping Down.)

July 3, 2017

NEPOOL Participants Committee Briefs: June 2017

Summer heat hit New England early this year, with load peaking at 20,181 MW on May 18 as temperatures in Boston and Hartford topped out in the mid-90s, resulting in transmission and unit outages and reductions that led to operational constraints, congestion and divergent pricing.

ISO-NE, which had 5,700 MW in planned outages, was hit with another 2,790 MW in forced outages at the peak hour ending at 6 p.m., COO Vamsi Chadalavada told the summer meeting of the New England Power Pool Participants Committee on Tuesday in his operations report for May.

Chadalavada said that the grid operator initiated an abnormal conditions alert (master/local control center procedure no. 2) at 9:30 a.m., which lasted until 10 p.m.

The Hydro-Quebec Phase II import limit dropped from 1,760 to 1,000 MW, while the NY-Northern Interface was nearly full at peak as total transfer capability dropped to 900 MW due to line outages. Northbound imports over the peak hours, coupled with constraints in Maine, resulted in congestion at the North-South Interface.

Fast-start generation was dispatched to meet the peak hour, pushing the average real-time price during the peak hour to $389.17/MWh, almost four times the average day-ahead price of $100/MWh. Real-time prices ranged from a high of $758.88/MWh in the Northeastern Massachusetts and Boston pricing zone, to a low of -$71.07/MWh for power from New Brunswick.

The energy market value in May was $283 million, up $3 million from April 2017 and up $67 million from a year ago. May natural gas prices were 4.7% lower than April but still 44% higher from a year earlier. Average real-time LMPs were $29.44/MWh in May, down 6.6% from April, but up 38% from a year earlier.

Committee Approves Settlement Terms for PER Complaint

Meeting in executive session, the Participants Committee on June 27 approved settlement terms that address all issues set for hearing in a dispute over the peak energy rent mechanism in the Forward Capacity Market.

In January, FERC granted a complaint by the New England Power Generators Association (NEPGA) against ISO-NE, agreeing that a penalty imposed during a summer heat wave proved that the PER is unjust and unreasonable (EL16-120). The commission agreed with the generators that the PER adjustment should be raised but said the amount should be determined in an evidentiary proceeding if stakeholders could not reach a settlement. (See ISO-NE Scarcity Rules Unfair to Generators, FERC Says.)

The settlement term sheet was approved by a show of hands with one vote in opposition and several abstentions.

The motion authorized officers of the Participants Committee to approve the formal settlement offer on the condition that all six committee officers agree. If the officers do not agree unanimously, the committee would need to hold a special meeting on July 14, 2017.

According to a memorandum from NEPOOL counsel David Doot, an agreement on Tariff language needs to wait until the commission rules on the issue of how to reflect capacity invoices issued after the refund effective date of Sept. 30, 2016. “Accordingly, the plan now is to finalize and file an offer of partial settlement without tariff language, and to approve changes to the tariff only if and after FERC rules on the proposed partial settlement and this unresolved, contested issue,” the memorandum said.

Terms of the settlement were not publicly disclosed.

NEPOOL Approves Tariff Changes for DR Integration

The Participants Committee on June 28 approved four Tariff amendments related to the June 2018 full integration of demand response resources (DRRs) into the energy, reserves and capacity markets. The changes integrate DRRs into the base Price Responsive Demand market design, as well as into new market designs implemented since the last New England Tariff filing under FERC Order 745 on DR compensation.

— Michael Kuser