Costco Stays with Dominion, Va. Commission Rules

By Christen Smith

In a ruling that highlights growing rifts in Virginia’s electricity sector, the State Corporation Commission rejected Costco’s bid to buy power from utilities across state lines, saying that keeping the retail giant a customer of Dominion Energy best serves the public interest.

The SCC ruling handed down June 1 prevents the company from aggregating its total electricity consumption to take advantage of a 2007 state law that allows large-scale customers with a peak demand of 5 MW or higher to shop around for suppliers The law provides the SCC with broad discretion for how to apply it.

While the commission agreed with Costco’s contention that Virginia’s regulatory framework supports unjustified rate hikes, it shifted the burden onto the state legislature to solve the issue of rising energy costs.

Virginia
| Dominion Energy

The SCC noted Dominion’s “rate-captive” customers have faced “a decade of rising rates and the likelihood of even higher rates in the future.” Allowing Costco to abandon Dominion under existing rules, the commission said, would force other ratepayers to make up the $1.57 million in lost annual revenues.

Although the state law enshrines an “escape valve,” the SCC determined it unfair for Costco to save money “at the expense of other customers.”

“This Commission will not allow small customers who cannot escape this structure, predominantly small businesses and residential customers, to be further burdened by the identified cost-shifting that will occur if larger customers like Costco choose to seek better deals for themselves outside of Dominion’s system,” the SCC wrote.

Costco argued “a wave of commercial customers leaving the utility through aggregated retail choice” would encourage Dominion to stop hiking prices to fund expensive system upgrades — often incompatible with clean energy goals. The commission denied Walmart’s request in February, while petitions from Target, Kroger, Harris Teeter and Cox Communications remain outstanding.

In the filing, a Costco witness accused Dominion of “over-earning on its frozen base rates for a number of years,” creating an “enormously frustrating” incentive “to keep what I view as the customer’s money.”

Costco’s comments underscore the rising tension between retail choice advocates and Dominion Energy, Virginia’s dominant utility company and most generous corporate campaign donor. Last month, a coalition of unlikely allies launched efforts to bust up the company’s monopoly — more than a decade after state lawmakers officially abandoned the deregulated electricity market design — insisting its well-funded lobbying efforts leave ratepayers footing the bill for wasteful infrastructure spending. (See Va. Group Seeks End to Dominion Monopoly.)

Dominion contributed more than $452,000 to state candidates and committees last year, according to the Virginia Public Access Project, making it the commonwealth’s largest campaign donor within the energy sector. That same year, the utility also advised lawmakers on an overhaul of its regulatory framework that allowed it to invest a larger share of revenues in new projects, rather than refunding customers for “overpayments” — as the SCC often made the utility do in years past.

Greg Morgan, Dominion’s general manager of regulatory affairs, said companies only began using the aggregation clause to pursue retail choice last year, despite its existence since 2007.

The utility also defended its infrastructure investments during an interview Tuesday, citing plans for six new solar facilities with a combined 350-MW capacity in Virginia and North Carolina, scheduled to come online in 2020. Dominion also supports cutting greenhouse gas emissions in half over the next decade and by 80% by 2050.

When it comes to the SCC’s decision, Dominion agreed it best protects customers from the shifting burden of costs while still supporting the diversification of the utility’s energy portfolio to include more renewable resources. Le-Ha Anderson, a Dominion spokesperson, said the company offers many different rate structures for customers unhappy with costs — a much more reasonable alternative than leaving the company altogether.

CAISO’s RC West Earns NERC Certification

By Robert Mullin

CAISO said Monday its RC West operation has achieved a “major milestone” after attaining the NERC certification needed to begin providing reliability coordinator services to balancing authorities in California and parts of Mexico on July 1.

The certification — issued by the Western Electricity Coordinating Council through its delegated authority from NERC — marks a key step in transitioning RC oversight of the Western grid away from Peak Reliability, which last summer announced it would be ceasing operations by the end of 2019.

“The NERC certification is an important turning point in our effort to become the reliability coordinator for the Western region,” CAISO CEO Steve Berberich said in a statement. “This was a huge lift for our staff since beginning this venture in January 2018, and the certification speaks to the dedication and hard work across the organization.”

CAISO
CAISO’s RC West is on track to provide reliability coordinator services to 87% of Western Interconnection load by November. | CAISO

In early January 2018, CAISO announced it would “reluctantly” depart from Peak Reliability and create its own RC — just a month after Peak floated its plan to develop an organized electricity market in partnership with PJM, competing with the ISO’s own expansion efforts. (See CAISO to Depart Peak Reliability, Become RC.) By last July, it was evident Peak would lose most of its customers to CAISO’s lower-cost services, prompting the Vancouver, Wash.-based company to begin winding down its own operations and pull out of the joint effort with PJM. (See Peak Reliability to Wind Down Operations.)

Since then, CAISO has worked quickly to stand up RC West as the Western Interconnection, facing the uncertain journey of moving from two to five RCs, with SPP, BC Hydro and Gridforce also sharing in the carve-out of Peak’s former territory. (See RC Transition Fraught with Pitfalls, WECC Hears.) The Alberta Electric System Operator has historically acted as its own RC and will continue to do so after the dissolution of Peak.

WECC conducted its full certification review of RC West in late March, which consisted of an onsite visit by observers from WECC, NERC and one other RC, as well as at least one BA and transmission owner. During the process, RC West staff were required to provide any requested documentation and answer questions intended to demonstrate readiness for taking on the RC function.

RC West operators have been shadowing Peak’s operations since May 1, taking part in nearly every call, including an energy emergency alert event occurring just hours into the process, Director of Operations Tim Beach told the RC Oversight Committee last month (See RC West Moving Smoothly Toward July Handover.)

The shadowing process also has RC West staff “verifying system data, conducting operational analysis and monitoring system conditions using situational awareness tools,” CAISO said Monday. The RC function now includes 17 full-time operators working on rotating shifts, with one position still open.

Beginning July 1, RC West will become the RC for 16 California BAs and transmission owners, as well as CENACE in northern Mexico. A second certification review is slated for August, ahead of RC West taking on 24 additional entities on Nov. 1. By then, it will have assumed oversight for about 87% of the West’s load.

SPP and Gridforce last month both said they’re on track to begin shadow operations with Peak in August in preparation for a Dec. 3 transition date. BC Hydro will take over RC functions within its own British Columbia territory Sept. 2 after commencing shadow operations in July. (See New RCs Tell WECC Transition on Schedule.)

NERC Sees Summer Risks for Texas, Calif.

By Rich Heidorn Jr.

ORLANDO, Fla. — Most regions have sufficient resources to meet anticipated loads this summer, but Texas and California are at risk from potential natural gas shortages and wildfires, NERC reported Tuesday in its 2019 Summer Reliability Assessment.

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At meetings in Orlando Tuesday, NERC’s Mark Olson called the seasonal assessments the “bridge” between NERC’s 10-year long-term assessments and operators’ day-to-day planning. | © ERO Insider

The report, which covers June through September, noted ERCOT’s warning it may have to issue energy emergency alerts to respond to resource shortfalls as its summer reserve margin has fallen to 8.5%. (See ERCOT: More Capacity, but Emergency Ops Still Expected.)

Meanwhile, natural gas supply from interstate pipelines will be insufficient to power electric generation on summer peak load days in Southern California, requiring withdrawals from the Aliso Canyon storage facility. NERC also cited concerns over Southern California’s ramping capacity and transmission line shutdowns during wildfires.

ERCOT

ERCOT’s reserve margin dropped from 10.9% a year ago, the result of continued demand growth, delays in planned generation and the mothballing of the 470-MW Gibbons Creek coal-fired generator.

Although its 2018 reserve margin was below its reference margin of 13.75%, ERCOT survived without calling emergency alerts thanks to “high levels of generator availability, response to market signals and unit performance,” NERC said.

ERCOT’s operating plans include voluntary load reductions and power imports if needed.

ERCOT’s summer Seasonal Assessment of Resource Adequacy (SARA), released last month, said the grid operator may tap load resources that can provide operating reserves, use contracted emergency response resources and instruct utilities to employ load management and distribution voltage reductions. It may also import emergency power across its DC ties and ask switchable generators serving ERCOT neighbors to prioritize it instead.

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Texas RE-ERCOT Seasonal Risk Assessment | NERC

Ramping Concerns

In CAISO, NERC warns of shortages in resources with upward ramping capability, which it said could mean the need for imports to maintain system frequency and prevent load loss in late afternoons as solar generation output drops while loads remain high. “Should extreme temperatures extend over a large area to the point where neighbors lack surplus energy, load could be at risk from a shortage in ramping capability,” NERC said.

NERC said gas-fired generators in Southern California will need to tap fuel from storage because interstate pipelines may not be sufficient to meet peak loads. As a result, withdrawals from the Aliso Canyon natural gas storage facility would be necessary to ensure adequate fuel for generators in the area.

Restrictions on Aliso Canyon “remain an item of focus,” NERC said. High storage withdrawals during winter 2018/19 has meant below-average storage levels this summer.

“The Southern California Gas Company (SoCalGas) forecasts that it will be able to meet the forecasted peak day demand under a ‘best-case’ supply assumption even without supply from Aliso Canyon,” the report said. “However, under a worst-case supply assumption, supply from Aliso Canyon will be necessary to meet that forecasted peak day demand. Should operating restrictions result in natural gas supply curtailments that affect electric generation in the Southern California area, mitigation procedures that have been in place since 2016 can be used to maintain BPS reliability.”

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Summer 2019 anticipated/prospective reserve margins compared to reference margin level | NERC

Wildfires

NERC is also citing government warnings of an elevated risk of wildfires in the Western U.S. and Canada, noting utilities’ plans include shutting down transmission lines.

The April-June outlook from the National Interagency Fire Center, Natural Resources Canada and National Meteorological Service in Mexico predicted above-normal wildfire potential for California, the Pacific Northwest (Western Oregon and Washington), Western Alberta, British Columbia and Northern Mexico, NERC said.

In addition to preemptively de-energizing transmission lines in high-risk areas, utilities are using “enhanced vegetation management, equipment inspections, system hardening and added situational awareness measures,” NERC said.

Nevertheless, NERC said the risk of resource shortfalls in CAISO is lower this year than last summer, citing well above normal reservoir levels and mountain snowpack for “greatly reducing the potential for operating reserve shortfalls.” (See CAISO Predicts Plentiful Hydro, Gas Constraints.)

If CAISO activates its emergency operating plan — for example, in response to the inability to meet spinning reserve requirements — it will employ a number of mitigation measures to minimize loss of load, NERC said including the following:

  • The Flex Alert program, which can reduce peak loads
  • The Restricted Maintenance program to reduce forced outages
  • The performance of manual post day-ahead unit commitment and exceptional dispatch of resources under contract to serve load and meet ramping requirements
  • The performance of manual exceptional dispatch of intertie resources with resource adequacy obligations to serve CAISO load
  • The use of demand response programs, including the Reliability Demand Response Resources (RDRR) under the “Warning” stage
  • The performance of manual exceptional dispatch of physically available resources not under capacity contract

UPDATED: RSC, OMS Approve Monitors’ Seams Study

By Tom Kleckner

State regulators in SPP and MISO on Monday separately approved recommendations to engage the SPP Market Monitoring Unit and the MISO Independent Market Monitor to conduct a joint analysis on seams issues between the two grid operators.

SPP
| ACES

The SPP Regional State Committee, meeting by conference call, agreed unanimously with the RSC-Organization of MISO States Seams Liaison Committee’s recommendation to work with the Monitors. The MMU and IMM brought a scoping plan to the Liaison Committee earlier in May, offering to identify and study seams issues, quantifying costs and benefits of proposed solutions when possible.

The recommendation directs the Monitors to immediately begin a Tier I study of market-to-market coordination, rate pancaking and joint dispatch.

A Tier II study following the completion of Tier I would focus on interface pricing, interchange optimization and regional directional transfer limits.

Both studies are to be completed by June 2020.

Tier III will serve as a parking lot for several other issues: exchanging firm flow entitlements in M2M transactions, targeted market efficiency projects, and outage and day-ahead coordination.

SPP
Shari Feist Albrecht | © RTO Insider

Kansas Corporation Commissioner Shari Feist Albrecht, who represents the RSC on the Liaison Committee, said stakeholder comments on potential study subjects centered on rate pancaking and joint dispatch.

“We decided that might be a significant issue from a state perspective,” Albrecht said. “We’re just trying to get some ballpark numbers to identify potential savings.”

Albrecht hopes the Monitors can finish their Tier I work in “six months or so,” then move on to Tier II.

The MMU’s Greg Sorenson addressed RSC concerns that the study would add incremental costs, saying the Monitor’s goal is to conduct four independent market studies each year; the RSC/OMS analysis would serve as one of those four studies.

The OMS Board of Directors also voted overwhelmingly to approve the Monitors’ joint study Monday in an email ballot, with 14 members in favor, one abstention and two non-participants, Executive Director Marcus Hawkins confirmed.

“Since both boards have approved the scope and prioritization, the monitors will now start to develop their work plans on the first phase of the study,” Hawkins said in an email to RTO Insider.

MISO stakeholders at a June 4 Seams Management Working Group conference call asked why the study was being conducted by the Monitors rather than RTO staff.

“We were looking for some independent analysis,” Missouri Public Service Commission economist Adam McKinnie explained.

The Liaison Committee has been meeting since mid-2018 to help improve the grid operators’ interregional coordination, which has never produced a major project. (See MISO, SPP to Ease Interregional Project Criteria.) That has frustrated some stakeholders and caused market inefficiencies.

Committee members will meet July 21 at the National Association of Regulatory Utility Commissioners’ summer policy summit in Indianapolis. The committee has invited FERC commissioners and staff to attend.

Amanda Durish Cook contributed to this article.

New England Regulators Talk Wholesale Market Evolution

By Michael Kuser

HARTFORD, Conn. — New England regulators are struggling to deal with how rapidly public policy is transforming the region’s wholesale electricity markets, state officials said Monday at the New England Conference of Public Utilities Commissioners’ (NECPUC) 72nd annual symposium.

As if to drive home the point about the pace of change, Connecticut Gov. Ned Lamont alerted the conference that his state would expand its offshore wind commitment more than six-fold.

NECPUC
The New England Conference of Public Utilities Commissioners (NECPUC) opened its 72nd annual symposium on Monday, June 3. | © RTO Insider

“We had a 300-MW commitment, and our legislature, virtually as we speak, is going to up that commitment to 2,000 MW … over the next five to seven years,” Lamont said. (Two OSW bills — Senate Bill 975 and House Bill 7195 — were on Monday’s Senate agenda.) He was speaking just days after the Massachusetts Department of Energy Resources issued a report calling for that state to solicit an additional 1,600 MW on top of an existing 1,600-MW procurement.

NECPUC
Ned Lamont | © RTO Insider

“We’re doing the right thing to make sure we have a carbon-free future and a reliable, predictable energy source that allows our region to continue to grow and prosper,” Lamont said.

The governor said he had faced an energy crisis shortly after being elected last November.

“I got a call from [Department of Energy and Environmental Protection Commissioner] Katie Dykes, who said we may have an issue with Millstone, the nuclear power plant that supplies 50% of our electricity,” Lamont said, referring to Dominion Energy’s threat to shut down the 2,111-MW plant, claiming it was no longer financially viable.

NECPUC
Katie Dykes | © RTO Insider

In December, Millstone was thrown a lifeline as one of the winning bidders in a state solicitation for nearly 12 million MWh of zero-carbon energy, securing purchase of about half its output for 10 years. (See Conn. Zero-Carbon Awards Include Nukes, OSW, Solar.)

“We solved that Millstone problem … and I’m going to make sure that no governor gets stuck again in the same situation I was,” Lamont said.

Market Disconnect

Restructuring of the electricity industry was meant to shift risks from ratepayers to the market players who stood to profit from their investments, said Sharon Reishus, president of Reishus Consulting and former chair of the Maine Public Utilities Commission.

NECPUC
Sharon Reishus | © RTO Insider

“There was not an explicit design of the wholesale markets to address state environmental goals. There was an assumption that you would not harm environmental goals,” Reishus said.

In moderating a panel on markets, Reishus asked: “How do state energy procurements keep from shifting risks back to consumers, and what are the risks of unintended consequences?” She added that the regional wholesale market may not survive if states continue to pursue their own separate goals.

NECPUC
June Tierney | © RTO Insider

New England has seen a disconnect between the roles of state policymaking and the design of the markets, said Vermont Department of Public Service Commissioner June Tierney.

“There’s this tension in the market design between affording the states the proper” authority to pursue environmental goals and the mission of the grid operator to secure reliable energy at the lowest cost possible, Tierney said.

“The market exists to serve the needs of six sovereign states … which push much more in the same direction than in contrary ones,” she said. “It’s about using American ingenuity to … meet a basic need our citizens have, which is the need for electricity.

NECPUC
Matthew Nelson | © RTO Insider

“When we were struggling with CASPR [Competitive Auctions with Sponsored Policy Resources] … the bottom line of that issue was that ISO-NE was engaged in tweaking market design,” Tierney said.

Pointing to Split FERC Approves ISO-NE CASPR Plan.)

Commissioner Richard Glick’s dissent caught her attention, she said. Glick contended that FERC had misinterpreted the Federal Power Act, failing to respect “that states, not the commission, are the entities primarily responsible for shaping the generation mix.”

NECPUC
R. Bruce Williamson | © RTO Insider

“It isn’t FERC’s job to interpret the Federal Power Act as if the states didn’t have legitimate interests in propagating laws that effectuate renewable energy policy,” Tierney said.

Answering Reishus’ question about unintended consequences, Maine PUC Commissioner R. Bruce Williamson said, “In Maine, it’s a constant battle. We have to remind, even to unwilling ears, that there are cost implications to some of the great ideas.”

The region sees the benefit of retaining existing carbon-free resources in the market, but there is a misperception that state procurements of energy drive prices higher, Massachusetts Department of Public Utilities Chairman Matthew Nelson said.

NECPUC
Nicholas Ucci | © RTO Insider

“Out-of-market contracts get seen as the bogeymen here, but the most recent one occurred in Massachusetts and actually saw real reductions to ratepayers,” Nelson said. “We live in a complicated market, and ISO-NE is doing its best … but there’s no going back to a vertically integrated electricity market.”

“Folks start realizing they are paying for a renewable project in their bills, but [they] don’t understand the benefits,” said Nicholas Ucci, deputy commissioner of energy with the Rhode Island Office of Energy Resources.

“No system is perfect, especially one that is two decades old,” Ucci said. “This is a work in progress.”

NECPUC
Left to right: R. Bruce Williamson, Maine PUC; June Tierney, Vermont DPS; Nicholas Ucci, Rhode Island OER; Katie Dykes, Connecticut DEEP; Kathryn Bailey, New Hampshire PUC; Matthew Nelson, Massachusetts DPU; and consultant Sharon Reishus. | © RTO Insider

Prayers Answered?

DEEP Commissioner Dykes said Connecticut has “gone from a minimal percentage of our load contracted to … close to 100%.”

“The contracting will only go so far,” Dykes said. “We have to assume that states are going to continue pursuing their environmental goals. The real question is: Are we going to do so in a coordinated way?”

NECPUC
Kathryn Bailey | © RTO Insider

New Hampshire Public Utilities Commissioner Kathryn Bailey noted that in 1996, her state was the first in the country to pilot restructuring utilities.

“Customers now have the ability to purchase their energy through competitive suppliers,” Bailey said, adding that the emphasis on least-cost generation resulted in an overreliance on natural gas.

Now, as regulators and ISO-NE work to both mold and adapt to a new resource mix, “utility-scale storage will be the answer to the prayer that we have today, and we’ll be able to balance the reliability with the long-term contracts that continue to be negotiated,” Bailey said.

“Having storage is really flexible and it’s probably going to be the answer … when we still need flexible resources, but 50% of the demand is powered by long-term contracts,” Bailey said.

MTEP 19 Could Yield First MISO SATA Project

By Amanda Durish Cook

An American Transmission Co. effort to improve reliability in central Wisconsin could within two years provide MISO with its first-ever storage-as-transmission asset (SATA) project.

ATC is proposing to build a 2.5-MW/5-MWh battery on a 138-kV line in the Waupaca, Wis., area, installing two capacitors and upgrading a nearby 69-kV bus to accommodate the project. The project would cost an estimated $9.1 million and be in service at the end of 2021. ATC said the battery would be available for two-hour discharge times.

The company is proposing the project for inclusion in MISO’s 2019 Transmission Expansion Plan (MTEP 19) to function as strictly transmission. MISO is so far prohibiting SATA projects from also providing market services. (See MISO Limits Storage as Transmission Asset Ownership.)

During a West subregional planning meeting Friday, MISO staff said the project still requires study, including determining how it could impact load service risks and system reliability. The RTO said it will present final project justification results at another subregional planning meeting on Aug. 23.

The company has also submitted two alternatives — another battery farther north and a traditional wires solution — in the event that MISO finds negative impacts from the originally submitted battery format. The 5-MW/10-MWh alternate battery project would cost $10.4 million, and a rebuild of the Whiting Avenue-Hoover 115-kV would cost $12.4 million. Both would stick to a late 2021 timeline.

ATC said its preferred battery project is designed to more reliably maintain up to a 155-MW load level, capturing more than 90% of historical load levels in the Waupaca area. The area is currently at risk during multiple outage conditions, MISO expansion planner James Slegers said.

“At certain load levels, the system cannot sustain the load,” Slegers said.

Waupaca contains a local 69-kV system supported by a nearby multi-segment 115/138-kV transmission line. MISO said local loads cannot be sustained when both ends of the 115/138-kV supply line are out of service. ATC currently uses an operating guide to open line segments to serve load radially on the 69-kV system after load levels reach a certain point and after a first outage. While the operating guide allows loads to be served after a second contingency, it places up to 114 MW of load at risk of disconnection, according to MISO. ATC’s battery is designed to operate after a second contingency.

“There are not many hours in a year that you could take a maintenance outage and not sectionalize the system,” Slegers said, adding the solution aims to allow multiple maintenance outages without a loss-of-load risk.

MISO has completed a reliability assessment on the battery project. So far, it found the most effective siting of a SATA solution is near the Harrison 69-kV substation in the area, although other nearby 138-kV buses between Arnott and Waupaca “performed similarly well.”

MISO Manager of Expansion Planning Lynn Hecker said the RTO has so far been using a conservative, approximately 20-year life cycle assumption in battery reliability studies.

The RTO has yet to develop life cycle cost comparisons for ATC’s battery and alternate projects.

Slegers said MISO is open to studying even more project alternatives, if stakeholders offer them. The RTO has said it will work with stakeholders “to understand technical details and evaluate any additional alternatives proposed.”

He noted that the ATC project evaluation will serve as a starting point and “lessons learned” for other SATA projects proposed in future MTEP cycles.

SPP Tx Planners at Forefront of New Challenges

By Tom Kleckner

LITTLE ROCK, Ark. — The predominance of renewable energy and battery storage in the nation’s RTO interconnection queues is certainly no secret.

SPP’s queue is dominated by 51.8 GW of wind projects in all stages of study and development. That’s on top of 21.6 GW of installed wind capacity and another 7.7 GW of unbuilt projects with signed interconnection agreements. Layered on top of that is 25 GW of solar projects in the queue — 215 MW is already installed — along with 4.5 GW of battery storage.

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Engineering Planning Summit attendees listen to SPP’s Jay Caspary. | © RTO Insider

Casey Cathey, SPP manager of reliability planning and seams, listed those numbers as he moderated a panel Thursday devoted to planning for an evolving grid.

“What’s our next challenge?” Cathey asked ITC Holdings’ director of regional planning, Alan Myers.

“Isn’t that enough?” Myers responded, drawing laughter from those gathered last week for SPP’s Engineering Planning Summit.

Turning serious, Myers offered a response: “It’s matching that variable to the variability of the load.”

“It used to be generation was the variable. Now, we’re seeing load becoming a huge variable,” said fellow panelist Holly Carias, NextEra Energy Resources’ director of origination. “It will take different technologies to maximize what we already have. Not only with transmission, but on the load side. We have to focus on providing service to the end customer and give them a better customer experience.”

Daniel Brooks, who manages the Electric Power Research Institute’s grid operations and planning research group, threw a wrench into the discussion when he reminded the panel and audience, “EVs are coming.”

Brooks said 10 to 20 years ago, automakers were first attempting to turn a car’s wheels with batteries.

“Listen to those [original equipment manufacturers] today. They’re completely committed to moving to electric vehicle fleets,” he said. “Some heavy-duty vehicle fleets are talking about multi-megawatt charging stations. That’s a challenge, but an opportunity as well.”

As Brooks is fond of saying, “It’s tough to make predictions, especially about the future.”

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Evergy’s Katy Onnen (left) listens as co-worker Derek Brown asks a question. | © RTO Insider

So far, SPP has been pretty successful with its forecasts. It says its planning efforts have resulted in $10 billion of construction projects over the last 14 years, allowing the RTO to focus on smaller upgrades and reliability projects.

The RTO’s Board of Directors in April approved a $1.8 billion Transmission Expansion Plan that will build projects in 13 states over the next five years. Members last year completed 98 transmission system upgrades in seven states at an estimated cost of $779 million.

A 2016 SPP study indicated $3.4 billion of transmission upgrades during 2012-2014 resulted in more than $240 million in fuel-cost savings for SPP members during the first year of the Integrated Marketplace. The RTO has said it expects the benefits to exceed a net present value of $16.6 billion into the 2050s, with a benefit-to-cost ratio of 3.5. (See SPP Begins Promotional Campaign to Tout Transmission Value.)

‘Big Boys’

“Transmission planning provides a lot of value, particularly when it results in construction,” SPP Engineering Vice President Lanny Nickell said in opening the summit Wednesday. “We have a lot of metrics that have determined we do provide a lot of value through the expansion of transmission.”

Stakeholders reviewed the transmission projects that could make up the 2019 Integrated Transmission Planning assessment, which will go before the board in October for approval.

The 2019 portfolio’s cost could be as high as $407 million, though staff estimate the projects could provide as much as $2 billion in benefits. Several of the projects target the southern corner of SPP’s footprint in Kansas and Missouri. There, congestion on MISO’s side of the seam has resulted in more than $60 million in market-to-market payments to SPP since March 2015. Constructing new 345-kV lines in the area could cost as much as $158 million, according to one proposed project.

Cathey noted SPP can no longer look at other RTOs — and Denmark and Germany, both leaders in renewable integration — for guidance on the ratemaking that will eventually help pay for the lines.

“SPP is kind of at the forefront of some of these challenges. We’re kind of the big boys now,” he said.

SPP
Antoine Lucas | © RTO Insider

“A big gap I see is that relationship between planning and regulatory. We’ve always been on the tail end. We find out what the regulatory decision is, then we scramble to make our plan fit that,” SPP Planning Director Antoine Lucas responded. “I don’t think we can expect that we’ll drive the regulatory process, but there has to be some form of collaboration on the front end to develop solutions that benefit both sides. It will be a big value-add if we can figure out ways to work in different partnerships with different organizations to tackle these problems.”

As the summit wound to a close, Jay Caspary, SPP’s director of research and development and special studies, reminded stakeholders that the RTO and its members will also have to deal with the footprint’s aging infrastructure, some of which is more than 60 years old.

“We’ve got to manage these assets in the field,” he said, referring to himself as an “aging asset too.”

“There are a lot of uncertainties, but one thing that isn’t is that time marches on. These things are getting older by the day. I want us to get ahead of that.”

“There’s a lot to consider. It’s not like it was 10 years ago,” Cathey said. “These will be interesting times moving forward. We’ll see if we’re accurate with our transmission planning as we were with all the transmission we built 20 years ago.”

NERC Team Seeking SOL Data to Answer FERC Concerns

By Rich Heidorn Jr.

A NERC panel considering a proposal to limit reporting on system operating limit (SOL) exceedances will be seeking data to support its claims that excessive compliance requirements are a reliability threat.

Members of the standards development team (SDT) for Project 2015-09 (Establish and Communicate System Operating Limits) will be gathering the data in response to concerns by FERC staff over a proposal that would require logging, communication and documentation only when SOL exceedances last for 30 minutes or longer.

The proposal, which came in response to comments by the Midwest Reliability Organization, has received “a lot of positive feedback from industry,” SDT Chair Vic Howell, of Peak Reliability, told stakeholders Wednesday. Current NERC standards do not clearly define what is an SOL exceedance or when it must be reported, he said.

Howell provided a briefing on a May 2 conference call that he and several other SDT members had with FERC staff on the proposal.

“It wasn’t very clear [to FERC] that this was a reliability issue as much as it was a compliance issue. … We tried to explain that it is a reliability issue because if operators are so busy doing all this documentation for compliance evidence, it takes their eye off the ball for performing actual operations and addressing actual SOL exceedances,” Howell said. “We got to a place where FERC staff understood our concerns and … they wanted us to come up with data to back up our concerns.”

SOL

System operating limits development in the operations horizon | SPP

Following the FERC call, Stephen Solis of ERCOT compiled preliminary statistics to facilitate discussions of what the actual data request could look like. The preliminary data showed that in January, about 2% of the Texas grid operator’s five-minute exceedances of pre- and post-contingency thermal or voltage limits lasted longer than 30 minutes. He acknowledged that ERCOT’s data includes 69-kV lines that are below NERC’s Bulk Electric System threshold and a number of non-exceedances that show up as the values approach close to an exceedance.

Reporting only the exceedances of more than 30 minutes would require almost 40 communications a day, Solis said. “The rest of it is just normal everyday seeing things, responding; seeing things, responding; repositioning the system very quickly.”

Solis said if ERCOT had to report each of the nearly 76,000 five-minute exceedances for the month, “we’d have to hire two or three people just to get on the phone and call people.”

“It’s not realistic and that would be a detriment to reliability,” he continued. “Of every 50 violations, one will make it greater than 30 minutes. We’re doing a very good job of catching things, fixing things. If you’re going to penalize companies for doing a good job, there’s something broken there.”

Howell said the team will seek data from MRO and others outside the SDT but that it would not be an industry-wide effort. “Whoever we can get to give us the data and do the data analysis so that we have a good representation and a reasonable pool, then we’ll go with that,” he said.

FERC staffer Eugene Blick, who participated in the Wednesday SDT meeting, suggested the team obtain data from “multiple [reliability coordinators], because keep in mind, what you’re proposing to change is in a continent-wide standard applicable to all RCs and all [transmission operators].”

Blick said one other entity that commission staff have spoken to didn’t see the issue as a problem. “They didn’t have many SOL exceedances during their operating day because their [operational planning analysis] served as a means to filter or mitigate some of the SOL exceedances.”

He said seeming exceedances that result from telemetry or modeling problems should be excluded in the data collection.

Howell said the team will spend the next couple weeks refining its data request before seeking contributions.

ERO Budgets up 3.8%; Assessments up 2.9%

By Rich Heidorn Jr.

NERC and the regional entities are proposing almost $207 million in spending in 2020, a 3.8% increase. Assessments are projected to increase by 2.9%.

The Electric Reliability Organization Enterprise budgets include a 9.8% spending increase for the Midwest Reliability Organization, which is absorbing the former SPP Regional Entity’s compliance enforcement duties, and a 35.2% jump for SERC Reliability, which is expanding to peninsular Florida with the phase out of the Florida Reliability Coordinating Council. (See FERC OKs SERC’s Expansion into Florida.)

Including the elimination of about 21 jobs at FRCC, and the addition of 20 at SERC, total ERO Enterprise headcount is projected at about 698, an increase of about 18.

The preliminary budgets were presented to the Board of Trustees’ Finance and Audit Committee (FAC) meeting Thursday. Final draft budgets will be posted July 15 and discussed at a July 18 FAC webinar. The board is scheduled to approve the budgets on Aug. 15 and submit them for approval by FERC and Canadian authorities Aug. 26.

The Compliance Monitoring and Enforcement Program (49%) and Reliability Assessment and Performance Analysis (18%) account for two-thirds of the ERO Enterprise’s spending.

NERC’s proposed budget is almost $83 million, a 3.8% increase driven by a 13.3% boost in spending for the Electricity Information Sharing and Analysis Center (E-ISAC). Excluding the E-ISAC — which will account for 11% of the ERO Enterprise budget and 27% of NERC’s — the organization’s spending will decrease slightly. (See “E-ISAC Continues Growth,” NERC Technology & Security Committee Briefs: May 8, 2019.)

In presentations to the committee, the REs projected salary inflation of about 3 to 3.5%, and benefits increases ranging from about 5 to 6% for MRO and SERC to 14% for Texas Reliability Entity.

TRE is also projecting its rent and utilities costs will increase nearly 28% when it renews the lease on its Austin headquarters in late 2020.

ReliabilityFirst’s budget, which is increasing 4.4%, includes funding for “overlap” hires to prepare for the departure for retiring employees. About 11% of RF’s employees are at or over retirement age.

SERC is projecting a 35% increase in meeting and travel costs related to the addition of the FRCC entities and the expansion of its board Executive Committee to 15 from 12.

Stakeholders: MISO System Fix Too Late for Summer

By Amanda Durish Cook

MISO’s effort to improve a key communication system will come too late to smooth summertime emergency procedures, stakeholders said last week.

In post-mortems of a January emergency event in which less than a quarter of load-modifying resources (LMRs) performed to the RTO’s criteria, multiple stakeholders complained the MISO Communications System (MCS) was difficult to understand and navigate.

The poor generator performance resulted in MISO last month issuing market participants nearly $2 million in penalties and disqualifying 21 LMRs for the remainder of the 2018/19 planning year. (See “MISO: $2 Million in Penalties for Jan. 30 LMR Underperformance,” MISO Reliability Subcommittee Briefs: May 2, 2019.)

As a result, MISO is seeking to improve how LMR owners interact with the nonpublic MCS webpage. (See MISO to Fix Communications System Shortcomings.)

During a Reliability Subcommittee (RSC) conference call Thursday, Chair Bill SeDoris said the low LMR success rate in January is evidence of “serious procedural issues on both sides of the house.”

Customized Energy Solutions’ Ted Kuhn criticized the RSC for scheduling MCS improvement discussions for the third quarter, saying MISO is likely to call multiple summertime emergencies using an inadequate system while market participants wait on improvements.

“The current MCS is not sufficient. … Some of these things need to get fixed,” Kuhn said. Other call participants repeated the plea for quicker improvements.

MISO
Ron Arness | © RTO Insider

SeDoris said MISO’s nonpublic Reliable Operations Working Group (ROWG) has taken up short-term improvements, including clearer communication when the RTO terminates a maximum generation alert.

Ron Arness, MISO director of Central Region operations, said the ROWG had a “healthy” discussion on how to improve usability of the MCS on Wednesday.

“There are some changes coming; those changes aren’t going to occur overnight. … Be patient with us,” Arness said.

But stakeholders say a mid-May emergency in MISO South already illustrates that the MCS is ill-suited for emergency communications. WPPI Energy economist Valy Goepfrich said when MISO called the May 16 maximum generation alert, it wasn’t clear the alert only extended to the South region.

MISO South May Emergency

MISO said the five-hour May 16 emergency was atypical, the result of a higher-than-normal forced outage rate combined with above-average temperatures and the usual spring maintenance season.

“While unplanned outages are expected, the successive loss of [about] 4 GW of generation in a short period of time is outside normal expected operating conditions,” MISO said.

Outages and derates in MISO South reached 16.6 GW that day, and load obligations hit a peak of about 27 GW around 5 p.m. MISO said it was able to maintain reliability through two separate calls for LMRs with lead times of three hours or fewer. The RTO will provide LMR response data at a later date.

MISO
MISO South May 16 emergency (megawatts) | MISO

Arness said MISO South frequently experienced tight capacity conditions over the last three weeks of May.

The RTO expects tight operating conditions in South through June due to hotter weather and continuing maintenance activity. Arness told stakeholders to be prepared for more emergency alerts in the region.

Goepfrich noted that MISO didn’t come close to hitting the North-South transfer limit during the event and asked that it ensure that transfer capability is used before it calls on LMRs.

Outage Exemption Talk Ongoing

MISO last week also said it will expand a penalty exemption to include resources that return early from a planned outage, part of new outage scheduling rules.

The RTO will exempt resources from accreditation penalties if the start and end date of their submitted outages remain within 10% of the originally scheduled outage window “and/or [the resource] reduces the capacity of the outage” to provide MISO with more available capacity.

MISO originally proposed that unit owners submit a new outage request for both extended and shortened outages to allow it to evaluate the request based on maintenance margin supply predictions, putting a resource’s penalty exemption at risk. Units earn penalty exemptions if they schedule an outage at least four months in advance. However, stakeholders questioned the potential for MISO to revoke the penalty exemption on even shortened outages. (See “MISO Taking Second Look at Outage Change Penalties,” MISO Reliability Subcommittee Briefs: May 2, 2019.)

Jeanna Furnish, MISO manager of outage coordination, said the RTO still seeks to discourage “bad behavior” when participants schedule planned outages. She said significant shortening of outages impacts MISO data and forecasting and affects other available megawatts.

“We want the best information we can get about your outage schedule. We want you to return early if you reliably can … but we want to acknowledge this isn’t a free pass to schedule the longest outage you can then reduce,” Furnish said.

Some stakeholders still weren’t satisfied with MISO’s compromise.

“You’re creating a huge disincentive for generation to shorten their outages,” CES’ David Sapper said.

Furnish said she rarely sees generation return significantly early from outages, adding that many generators actually lengthen planned outages.

MISO Director of Resource Adequacy Coordination Laura Rauch said the RTO is seeking to “strike a balance” to prevent generators from scheduling longer-than-necessary outages simply for the wiggle room.

Furnish put the 10% proposal to a round of feedback and encouraged stakeholders to offer exemption alternatives.