Page 1296 – RTO Insider

July 25, 2017

States, Enviros Differ on Jurisdiction over Energy Efficiency

By Rory D. Sweeney

Environmentalists last week urged FERC to decide whether states can control participation of energy efficiency resources (EERs) in RTOs, while state officials said the commission should take no action.

The group Advanced Energy Economy petitioned FERC on June 2 to issue a declaratory order ruling that it has “exclusive jurisdiction” under the Federal Power Act to regulate EER aggregators involved in wholesale markets (EL17-75). AEE further requested that FERC make clear that retail regulators, such as state public utility commissions, have no such authority unless FERC grants it to them.

The group — whose members include Johnson Controls, Landis+Gyr, Lockheed Martin and other technology companies — asked FERC to rule after PJM began a stakeholder process to examine how it allows EER aggregations to participate in its wholesale markets. The initiative also was to investigate the potential for creating an “opt out” mechanism for regulators like what PJM developed for demand response in response to Order 719.

FERC environmentalists energy efficiency — Drom | © *RTO Insider*

PJM’s initiative began after the East Kentucky Power Cooperative discovered an aggregator was attempting to sell into the RTO’s markets EERs that originated in its distribution territory. EKPC requested a legal opinion from the state Public Service Commission, which responded and later provided a declaratory order denying aggregators the right to sell Kentucky EERs into PJM’s markets without receiving its blessing.

At the Kentucky commission’s request, PJM then proposed the stakeholder process, which received substantial discussion before being endorsed. Rick Drom, an attorney representing the still-unidentified aggregator in Kentucky, argued that the process was “a flawed solution seeking a problem,” while PJM’s Denise Foster defended the RTO’s actions as reasonable preparation to develop appropriate rules should a regulatory agency act. (See “EE Problem Statement Narrowly Approved,” PJM Market Implementation Committee Briefs.)

Stakeholders from around the country weighed in last week before the deadline on filing comments. PJM said it neither supports nor opposes the petition, but it asked FERC to clarify states’ role “relative to retail customers that participate, either directly or indirectly, as supply-side EERs in the PJM capacity market.”

The Sierra Club, the Natural Resources Defense Council, the Sustainable FERC Project and the Environmental Defense Fund filed in support of the request. They supported AEE’s argument that there is no “nexus” between aggregating the EER credits and impacts on retail electricity usage.

“Because the transaction creating the EER occurs at the level of the manufacturer or the distributor of the energy efficiency product, a retail regulator’s authority over retail customers is not implicated,” according to a joint filing from the environmental groups. “We urge FERC to issue a focused order that resolves the cloud of uncertainty hanging over the participation of wholesale EERs in PJM’s market, while carefully avoiding a broad determination of state-federal jurisdiction that would be unnecessary and detrimental to the flexibility inherent in the statute.”

It also asked FERC to “redirect” PJM’s stakeholder process, saying the RTO “wrongly predetermined the framing and outcome of the process to address concerns about retail interactions of EERs.”

The Organization of MISO States, the Kentucky PSC, Kentucky Attorney General Andy Beshear, the Illinois Municipal Electric Agency (IMEA), the American Public Power Association and the National Rural Electric Cooperative Association all filed in opposition to the petition.

The Kentucky parties, filing jointly, argued that the sales do “have a direct nexus with retail electric customers” and that EE aggregation pose a “significant, adverse impact” to load-serving entities in the state. Energy savings are not separate from sales because PJM defines EERs as a “continuous reduction” in consumption, they said.

“The Kentucky parties argue that such sales would solely benefit the EER provider to the detriment of the LSE’s retail ratepayers,” they said. “Absent a retail customer’s load reduction, there is no EER to participate in the PJM market. The fact that the EER bidder has no contract or agreement with the retail electric customer, who may not even know that it is participating in the PJM wholesale market, is irrelevant. If the retail electric customer’s load reduction is bid by an EER into the PJM market, that customer is indirectly participating in the wholesale market.”

Unknown aggregations would cost ratepayers money, they argued.

“Absent inclusion of the EERs in the resource assessment of a Kentucky utility, it will either over procure capacity, resulting in higher than necessary costs for retail customers, or have excess capacity that should have been sold to benefit retail customers. Thus, without participation through a tariff or special contract, EERs in Kentucky are being enriched by higher rates paid by the utility’s other retail customers,” they said.

IMEA asked FERC to reject the petition and let the PJM stakeholder process play out. It argued that allowing aggregators to pull out individual customers from LSEs can threaten their financial and resource planning while “allowing a customer that provides no benefits to the system or to Milltown’s [a fictional IMEA municipal member] other customers to access the revenue [streams] from PJM’s markets to the detriment of [the LSE’s] own system benefits and ratepayers.”

NRECA also said the petition was premature, as PJM hasn’t developed tariff language and Kentucky hasn’t taken any action to limit EER bids.

“Too many facts are unknown, and the scope of the declaratory relief being sought is ill-defined,” NRECA spokesperson Tracy Warren said. “And in no case should FERC revisit the basis for its 2008 order on DR bids, as the petition invites.”

OMS filed in support of using the same “opt out” process as developed for DR in Order 719. “Wholesale EERs present the same type of concerns that were raised during the robust process leading to the issuance of Order 719.”

The organization warned that allowing EE aggregator participation would impact utility planning and attainment of mandated efficiency targets.

“It’s worth noting that the single energy efficiency program type that AEE relies on throughout its petition, reducing product cost directly at a retailer/supplier, typically has a very high [benefit-to-cost] ratio and is often a centerpiece of utility energy efficiency programs. By allowing aggregators to sign up retailers and suppliers for purpose of generating wholesale EERs, those same retailers and suppliers are no longer available to utilities to implement their own programs. Furthermore, the utility may have assumed the availability of certain retailers to participate in a utility efficiency program,” OMS said.

July 25, 2017

SPP to Dissolve Regional Entity

By Tom Kleckner and Rich Heidorn Jr.

DENVER — SPP announced Tuesday it will dissolve its Regional Entity (RE), ending the reliability oversight role that had been a source of concern at NERC and FERC.

The RE is responsible for auditing and enforcing NERC reliability rules for 120 registered entities in three balancing authorities: SPP, Southwestern Power Administration and parts of MISO.

SPP said it was acting, in part, because of the expansion of its RTO footprint, which no longer aligns with the RE’s territory. Since 2007, SPP’s RTO has expanded to 14 states while the RE is limited to the original eight: all or parts of Arkansas, Kansas, Louisiana, Mississippi, Missouri, New Mexico, Oklahoma and Texas.

SPP NERC regional entity — SPP CEO Nick Brown announced Regional Entity’s dissolution as RTO Board Chair Jim Eckelberger listens. | © *RTO Insider*

“Given that the footprints of the SPP RTO and SPP RE no longer align — due to our significant growth over the last decade and in light of further potential expansion opportunities to the west … SPP’s executives, Board of Directors and Members Committee have made the strategic decision to focus on our core functions of reliability coordination, wholesale market operations and transmission planning,” CEO Nick Brown said in a statement. “I believe this is in the long-term best interest of SPP and our members.”

SPP said NERC had agreed to terminate the delegation agreement that appointed SPP as an RE in 2007. On Sunday, the RTO’s board and Members Committee voted to give Brown authority to terminate the delegation agreement, a decision the SPP RE Trustees endorsed on Monday.

Pressure from NERC?

SPP said it will work with NERC and FERC on the transition, which is expected to be complete by the end of 2018.

SPP sources said the decision came under pressure from NERC, which wanted to end RTOs’ RE functions. Brown’s statement said the decision had come “with the support and encouragement of NERC.” NERC spokeswoman Kimberly Mielcarek told RTO Insider that NERC “supports this decision and will work with SPP to ensure a seamless transition.”

SPP’s dual role had also caused it problems with FERC, which criticized SPP in a 2008 audit for failing to ensure the RE’s independence from the RTO (PA08-2, AD09-3). The audit called for improved oversight from the RE Board of Trustees to prevent conflicts of interest.

At the time, the RE had a budget of $4.6 million, for 12.4 full-time-equivalent employees, but it only had five full-time employees, with the remaining staff performing functions for both the RTO and RE.

In response to the audit, SPP agreed to eliminate all reporting relationships between RE and RTO employees. The RE now has 24 employees and a budget of about $10.8 million.

“We are going to move on,” Brown said at Tuesday’s board and Members Committee meeting. “Each and every time we entered into [renewing NERC’s delegated agreement], the relatively small size of the RE footprint and the connection between the RTO, the RE itself and our corporate compliance business [was an issue]. It was clear to us the continued renewing of that agreement was in jeopardy.”

When NERC first delegated compliance monitoring and enforcement authority to its REs, half of them were affiliated with registered entities, according to SPP, which said it is the only remaining organization to operate as both an RTO and RE. “When SPP dissolves the SPP RE, only one of the eight [Regional Entities] will remain affiliated with a registered entity, and no ISO/RTOs will perform RE functions,” SPP said.

Transition

Mielcarek said SPP will provide a transition plan to NERC for review.

“The 120 registered entities within the SPP footprint will be notified of the dissolution and given the opportunity to submit a written request to transfer to another Regional Entity. NERC will determine whether the transfer is appropriate based on various criteria, including geographic location, electrical boundaries and resources,” Mielcarek said.

All changes must be approved by NERC’s independent Board of Trustees, then filed with FERC for its approval. “The outcome of this intensive process will result in a more efficient and effective [Electric Reliability Organization] Enterprise and NERC looks forward to working with all affected parties,” Mielcarek said.

Regional Entity Trustees Chair Dave Christiano listens as GM Ron Ciesiel shares stakeholder feedback with board in December 2016 meeting. | © *RTO Insider*

Brown said the transition will take time. “It’s not something that’s done overnight. A lot of coordination has to occur between the SPP RE and the audits we have underway.”

Brown said there will be “much debate in the Members Committee” about the transition to another RE, and that NERC will facilitate many of the meetings.

24 Employees Affected

The RTO said it was “committed to ensuring the continued employment” of the 24 RE employees. “There’s a lot of interest in those employees,” Brown said. “They’ve done exemplary work over the last decade and are noted as experts by a number of professional entities.”

Dave Hudson, president of Xcel Energy’s New Mexico and Texas operations, complimented the RE staff on behalf of the members: “They are very professional in a hyper-technical area, and we appreciate working with them. The world changes, but these people are very competent and have a bright future in front of them.”

Dave Christiano, chair of the RE Trustees, responded: “They’re highly educated and highly prepared. A lot of our people are certified, which isn’t generally the case with other REs. We’re working with the other REs and NERC to ensure a good future for our employees.”

Mountain West: No Impact

Mountain West Utilities map | *Mountain West*

SPP’s RTO footprint expanded first with the addition of the Nebraska entities in 2009 and the Integrated System in 2015. SPP is currently wooing the Mountain West Transmission Group — two investor-owned utilities; two municipal electricity providers; two generation and transmission cooperatives; and two federal power marketing administration projects covering most of Colorado and Wyoming, along with parts of Nebraska, New Mexico, Arizona and Montana — to join the RTO. Adding Mountain West would mean including in the RTO’s Tariff all the DC ties between the Eastern and Western Interconnections, except for one in Canada. (See SPP, Mountain West Members Get Acquainted.)

Mark Stutz, spokesperson for Xcel Energy’s Colorado utility, said the dissolution of the RE will not impact Mountain West’s decision on joining the SPP RTO. “It is really an issue more local to the area in which it is occurring. The function of the Regional Entity (RE) is essentially one of standards compliance and enforcement. In the MWTG footprint, that’s currently handled by the Western Electricity Coordinating Council (WECC); if [a] regional transmission organization is formed in the Mountain West, this function still would be handled by WECC.”

[Editor’s Note: Editor-in-Chief Rich Heidorn Jr. participated in the 2008 audit of the SPP Regional Entity as a member of FERC’s Office of Enforcement.]

July 24, 2017

‘Devious’ Move Puts Md. Wind Projects out to Sea

By Rory D. Sweeney

Here’s a shocker: even politicians feel the need to keep up with the Joneses.

A congressman from Ocean City, Md., successfully inserted language into a U.S. House appropriations bill on Tuesday to effectively force two wind turbine projects to move farther offshore from his district.

Why? Because he apparently noticed that a project sited off Virginia was much farther out.

Rep. Andy Harris (R) got the amendment added to the 2018 appropriations bill for the U.S. Interior Department, EPA and other agencies. The amendment forbids any funds from being used to review wind projects that aren’t at least 24 nautical miles from the Maryland shoreline. The House Appropriations Committee voted 30-21 to send the bill to the House floor.

“They’ve got to put them further out, just like they’re doing in Virginia Beach,” Harris said during the hearing on the bill. “That’s all this does.”

Blinking Lights on the Horizon

Harris was referring to two projects approved in May by the Maryland Public Service Commission, which awarded offshore renewable energy credits to US Wind and Deepwater Wind’s Skipjack Offshore Energy. US Wind’s proposed 62-turbine, 248-MW project, to be built 12 to 15 nautical miles offshore at a cost of $1.375 billion, would begin operations in January 2020. Skipjack plans a 15-turbine, 120-MW, $720 million project 17 to 21 miles offshore that will be operational in November 2022. (See Md. PSC OKs 368 MW in Offshore Wind Projects.)

The PSC also considered visibility of the turbines from the shore, requiring US Wind to locate its project as far to the east of the designated wind energy area as practical. Commissioner Anthony O’Donnell also charged the developers with using the “best commercially available technology to lessen views of the wind turbines by beachgoers and residents, both during the day and at night.”

That’s not enough for Harris. The project off Virginia Beach announced earlier this month by Dominion Energy and DONG Energy will be sited 27 miles offshore. (See Dominion Plans 12-MW Offshore Wind Project, 2nd in US.)

“So, it’s not that the technology is not possible. It’s just … they want to save money. They want to bring it in close,” Harris said. “We want them to just site this out 24 nautical miles, or around the curvature of the earth.”

He accused the companies of not working with Ocean City officials and said that the turbines were initially planned to be shorter before the companies raised them. The only operational offshore wind project in the country is off Block Island in Rhode Island, but “this one is much, much larger,” Harris said.

His amendment would “either make them reduce the height a little bit or move them farther out so when you go to the ocean in Ocean City, Md., you’re not looking at red blinking lights on the horizon.”

‘It’s the Physics’

Rep. Ken Calvert (R-Calif.), the Interior Subcommittee chairman, supported the amendment but expressed concerns that it might have impacts beyond Harris’ local issue.

The subcommittee’s ranking member, Rep. Betty McCollum (D-Minn.), said the Congressional Budget Office estimated the amendment would cost the government $6 million in contract breaches and lost rental receipts — not including liabilities from economic losses — that will “most likely” be paid by EPA. She opposed the measure and pointed out that it interferes with the Maryland General Assembly’s action to incentivize offshore wind production. (See Maryland OKs Offshore Wind Bill.)

Harris’ amendment also removes $6 million in EPA funding for environmental programs and management.

Rep. Dutch Ruppersberger (D-Md.), whose Baltimore-area district neighbors Harris’, also opposed the measure. He said the PSC effort has been in development for 10 years, stands to create 5,000 jobs in his district and will raise $74 million in state tax revenue.

Ruppersberger’s district would gain additional benefits. The PSC order requires the developers to use Baltimore-area port facilities for construction, operations and maintenance, as well as to fund almost $40 million in upgrades at the Tradepoint Atlantic (formerly Sparrows Point) shipyard in Baltimore County and invest at least $76 million in a steel fabrication plant in the state.

Ruppersberger said he participated in the negotiations that got US Wind to move its project 17 miles offshore and was satisfied with a subsequent rendering of the view from the beach. However, US Wind’s website maintains the project it will be 12 miles offshore.

Rep. Marcy Kaptur (D-Ohio) called the amendment “precedent-setting” and said there are “more appropriate and technically precise ways to direct wind turbine placement” than by “advancing the site location through arbitrary and random legislative actions untethered to research or appropriate public review.”

She cited wind development in her region along the Great Lakes as an example and noted that the fastest-growing job category in that area is wind technician.

Harris countered that “there’s nothing arbitrary about this.”

“It’s the curvature of the earth. It’s the physics. It’s, ‘You will see these windmills unless they’re 27 miles out,’” he said, apparently forgetting that his amendment called for only a 24-mile setback. “This doesn’t kill the project, this delays it. … They’re halfway there.”

He cited a North Carolina State University survey in which 54% of respondents said they would be unwilling to stay wherever turbines are visible.

‘Underhanded’

Mike Tidwell, the executive director of the Chesapeake Climate Action Network, called the move “devious and underhanded” in a statement.

“Congressman Andy Harris is working to dismantle a yearslong, inclusive process to bring offshore wind to the shores of Maryland in a rider to a bill over which Marylanders will have no say,” he said. “Marylanders overwhelmingly want offshore wind because they know it would bring good jobs and boost the state’s clean energy economy.”

US Wind Director of Project Development Paul Rich told USA TODAY that the amendment would leave room for just one turbine.

“This is not helpful,” Rich said. “This stops a process before it’s even begun. It’s totally at odds with his constituency.”

July 24, 2017

Vermont Seeks ISO-NE Help on Tx Constraints

By Michael Kuser

Vermont regulators and utilities are working with ISO-NE to resolve transmission constraints in the northern part of the state, where the system has reached its capacity to accept additional generation.

At the center of the issue is the Sheffield-Highgate Export Interface (SHEI).

“While load levels [at the interface] vary within a tight band, generation can vary significantly because of the intermittency of wind and hydro generation resources. The other resources, including the Highgate HVDC converter, are relatively constant,” Vermont Electric Power Co. said during a presentation at a July 12 state planning meeting.

iso-ne transmission constraints — 63-MW Kingdom Community Wind farm in Lowell, VT | *Green Mountain Power*

Frank Ettori, VELCO director of ISO-NE relations and power accounting, said the utility would invite the grid operator’s Planning Advisory Committee to a special Vermont System Planning Committee session to help remediate the constraint. Potential solutions include a sub-transmission upgrade, battery storage and installation of an automatic voltage regulator on a generator.

ISO-NE created the SHEI to monitor system flows in relation to system capacity in real time after Green Mountain Power and Vermont Electric Cooperative built the 63-MW Kingdom Community Wind plant in Lowell in 2012. Three utility-scale generation projects — Swanton Gas (40 MW), Sheffield Wind (40 MW) and Kingdom Community Wind (64.5 MW) — have interconnected in the northern portion of the Vermont transmission system, and the constraints prevent them from running at full capacity at all times.

VELCO hired a consultant to help determine the costs of various solutions, with the initial report due in late August and the economic evaluation by October.

Geographic Locational Value

The committee also heard about state policy implications and approaches from Ed McNamara, director of planning with the state’s Department of Public Service (DPS).

With distributed generation, in particular energy efficiency, there’s always been an assumption of a positive geographic locational value associated with energy efficiency and renewables, McNamara told RTO Insider.

“In a constrained area, the thinking had been that constraints are associated with too much load,” McNamara said. “Now when you have an export-constrained area, you would be thinking of a negative geographic locational value. That’s something that our policy has never contemplated.”

McNamara asked questions rather than proposing solutions: Should the Public Utility Commission be looking at generation projects that might not produce a net positive amount of new renewable generation in an area? Should we consider a different valuation in the area that has an export interface? On energy efficiency, should we look at changing the cost-effectiveness screening for northern Vermont compared to other areas?

Fast-Changing State

Vermont now meets more than 20% of its peak load through net metering — including from solar. More than 100 MW of new wind has come online over the past 10 years, all for a 1,000-MW transmission system, according to the DPS.

“Our system has changed considerably and we need to start keeping our policies up-to-date,” McNamara said. “What happens in an export-constrained area where essentially you have one renewable unit cannibalizing the generation output of another renewable unit?”

And while net metering might reduce the value of energy efficiency in particular areas, the DPS has equity concerns for all ratepayers.

“We don’t want to discourage and say to one ratepayer just because you live in this area you don’t have the same access to net metering and energy efficiency as the customer 50 miles south,” McNamara said. “This is where we, the Department of Public Service, still need to get our heads around this.”

July 24, 2017

NARUC: Influx of Data Centers a Game Changer for Grid

By Jason Fordney

SAN DIEGO — The digital economy is driving construction of a massive amount of data and storage infrastructure that has many implications for the electricity grid, industry participants and regulators said last week.

Data centers are seen by states as bringing economic development, but they also create electricity and water demand that requires attention from regulators. Utilities and municipalities are designing tariffs specifically for data centers, which require significant infrastructure development within a certain utility footprint, Illinois Commerce Commissioner John Rosales said at a July 17 panel of the National Association of Regulatory Utility Commissioners’ Summer Policy Summit.

NARUC data centers energy storage — Panel discussion on data centers at NARUC | © *RTO Insider*

Rosales and others noted that the demand for data and storage infrastructure will only grow. “We are not putting down our smartphones or tablets anytime soon,” he said.

Commonwealth Edison Vice President Sheila Owens said that Northern Illinois houses 70 data centers with aggregate demand of more 200 MW, the largest 15 of which have annual demand growth of about 20% a year. She noted a dramatic statistic: 90% of the data ever created were generated in the past two years.

“Data centers are the manufacturers of the 21st century in our digital economy,” Owens said. She added that Chicago’s transportation access and colder climate benefit data center efficiency by reducing cooling costs.

Data centers have a high incentive to use energy and water efficiently, and many companies have sustainability offices that research siting concerns for them, Owens said. Legislation in Illinois has created incentives for using solar credits to commercial facilities. Data center operators tend to be interested in clean energy.

Former Florida Public Service Commissioner Eduardo Balbis said the number of data centers will increase in the U.S. as new technology, such as autonomous vehicles, is developed. He urged that state regulators partner with data center operators on energy-usage programs in order to attract the facilities.

States are now waiving taxes to account for data centers or adjusting rates, and regulators should give utilities flexibility to partner with data center operators, said Balbis, now managing director of Accenture Strategy.

July 24, 2017January 18, 2024

SPP, Mountain West Members Get Acquainted

By Tom Kleckner

DENVER — Before introducing a panel of Mountain West Transmission Group representatives during SPP’s recent Markets and Operations Policy Committee meeting, COO Carl Monroe assured everyone that they were sitting inside the cavernous Colorado Convention Center by pure happenstance.

“We set up this meeting in Denver two years ago,” before entering discussions with the group about SPP membership, Monroe said. “So, there is nothing nefarious by us having our meeting here.”

Not surprisingly, after Mountain West announced earlier this year that it intended to join an RTO, and preferably SPP, the MOPC meeting drew record attendance. SPP reported a head count of 185, with 173 attendees signing in. A good number of those were Mountain Westers — as those representing the organization’s various entities refer to themselves — and interested regulators from Colorado and other Western states.

Mary Ann Zehr, senior manager of transmission contracts, rates and policy for Tri-State Generation and Transmission Association, said Mountain Westers “showed up in force … to glean awareness of the SPP ‘process,’ stakeholder interactions and decision-making ability.”

They got a good dose of that, taking in a passionate, member-led discussion of cost shifts within the RTO’s transmission zones — an issue sure to be key should SPP integrate its new members. (See Divide Evident Between SPP Tx Owners, Users.)

“Members have been monitoring the zonal-placement discussion occurring in SPP for a few months now,” Zehr said. “Initial zonal construct and methodologies to address future zonal placement are critical decisional items.”

“We’re highly concerned about a lot of issues related to zonal placement,” said Joe Taylor of Xcel Energy, which owns Public Service Company of Colorado. “We don’t necessarily want to put ourselves at risk. We’re just not 100% resolved around how many zones there will be. Cost-shift negotiations among members … we’re not done with that.”

The Case for Membership

For his part, Monroe said he was pleased to have the Mountain West representatives present, saying they saw a demonstration of how SPP maintains its independence through membership diversity.

“They were able to witness firsthand the active engagement and meaningful voice our stakeholders have in the development of SPP’s policies, even during discussion of contentious issues,” Monroe said.

“My sense is that the group was pleased with the dialogue, ability to contribute and outcomes,” Zehr said. “It was also very helpful for members to be able to meet and have side discussions with existing SPP members.”

In return, Zehr and other Mountain Westers participated in a panel discussion, sharing background on each of their companies and explaining why the organization has decided to join an RTO.

Mountain West — comprising eight investor-owned utilities, municipalities, federal power marketing administrations and cooperatives, and their subsidiaries — announced in January that it was beginning discussions with SPP about joining. The group expects to arrive at a decision by October and could present a recommendation to the RTO’s Board of Directors in January 2018. (See Mountain West to Explore Joining SPP.

Mountain West members serve 6.4 million customers in and around the Rocky Mountains, with a coincident peak of more than 12 GW. Should the organization join, the new RTO’s Tariff would include all the DC ties between the Eastern and Western Interconnections, except for one in Canada.

“Our goal is to keep costs as low as we can for our customers by exploring any option,” said Platte River Power Authority’s Andy Butcher. “What does it cost versus the benefits? We believe there’s value, so that’s why we’re sitting at the table.”

A 2016 Brattle Group study found Mountain West could save $53 million to $71 million annually through 2024 by participating in a day-ahead market and replacing its nine tariffs with one. Eliminating pancaked rates for wholesale transactions and other tariff-revision concepts started the group’s dialogue about RTO membership.

Members said they also want to take advantage of modern market designs to maximize transmission capacity and use the most cost-effective generation. SPP’s Integrated Marketplace, with its day-ahead and real-time markets, is a huge selling point.

“Out here in the West, we use what we call available transmission capability,” Taylor told the MOPC. Noting that SPP’s transmission system is flowgate-based and Mountain West’s is flow-based, he said, “The [flow-based] contract methodology is very conservative. I think we’ll see great benefits without building additional transmission.”

Taylor also made a point of mentioning that, after the panel discussion, the Mountain Westers would be conducting their 70th meeting on Tariff revisions and RTO membership. They and SPP have formed a steering committee and working groups focused on governance, rate design, cost allocation, transmission planning, reliability coordination and the RTO’s Regional State Committee (composed of regulators from 10 different SPP states).

Comes Down to Business

SPP and Mountain West representatives have appeared twice before the Colorado Public Utilities Commission in a pair of information sessions. A third, focused on governance, has been scheduled for Aug. 24. (See Mountain West, SPP Tout RTO Membership to Colo. PUC.)

Monroe said SPP is following the same process it did when adding the Integrated System in 2015 and Nebraska utilities in 2009. The two sides are in confidential negotiations, with SPP staff keeping the board, RSC and Strategic Planning Committee updated during executive sessions.

“Most of the time is spent in educating both [parties], because there’s a lot to joining SPP, but we’re also trying to understand the parties that want to join, their concerns and how to address them,” Monroe said.

Asked whether Mountain West would be fully integrated with SPP’s Eastern Interconnection or on its own, Monroe said, “From an SPP staff perspective, we believe that having it all integrated together is the most beneficial form. SPP has technology it’s been exploring … and we believe it’s capable of running the market over the full footprint.”

In the end, each Mountain West utility will have to make a business decision.

“We’re doing that as individual companies,” Zehr said. “We have cost shifts associated with de-pancaking of transmission rates, we have implementation costs … lots of factors that drive our benefit costs as individuals.”

Other utilities from the region could also make the same business decisions about becoming RTO members, although they haven’t come out publicly.

“Because of some of the issues they’re still resolving among themselves, they haven’t added anyone to the party,” Monroe said.

Said Taylor: “Hopefully, in the future, all will be revealed.”

July 24, 2017

Texas City Files to Mothball 454-MW Coal Plant

The City of Garland, Texas, last week told ERCOT it wants to mothball a 454-MW power plant for all but the summer.

ERCOT coal plant reliability — | *Tom Harpool Collection, University of North Texas Special Collections*

The city’s municipal utility, Garland Power & Light, said it wants to run Gibbons Creek Generating Station only from June 1 to Sept. 30 each year, according to a notification of suspension of operations (NSO) filed Wednesday. The suspension would be effective Oct. 17.

Although Garland is a Dallas suburb, the 34-year-old coal-fired unit is located northwest of Houston. The plant is operated by the Texas Municipal Power Agency.

ERCOT stakeholders have until Aug. 2 to file any comments on the NSO as part of the standard reliability-must-run review.

The ISO also said on Thursday that it has determined a Union Carbide 40-MW gas-fired generator on the Texas Gulf Coast is no longer needed for transmission reliability needs and can be retired, effective Sept. 29. Union Carbide filed its NSO in June.

The cogeneration unit went into service in 2000. As a private-use network unit, it is connected to the ERCOT grid, but the load is netted with internal generation and not directly metered by the Texas grid operator.

— Tom Kleckner

July 24, 2017

MISO, Stakeholders Differ on New Queue Plan

By Amanda Durish Cook

Stakeholders are at odds with MISO over some aspects of the RTO’s new interconnection queue rules during a time when the queue is beset by “unprecedented” backlogs.

RTO staff said the sheer volume of prospective projects is creating an overwhelming definitive planning phase (DPP) study cycle this year.

MISO definitive planning phase DPP — | *MISO*

“It’s the largest queue we’ve ever had — over 200 projects,” Patrick Brown, executive director of transmission asset management, said at a July 18 Interconnection Process Task Force (IPTF) meeting. MISO is reviewing project applications and will update the list of queue projects based on study findings by the end of July.

But multiple stakeholders have asked that queue implementation details be fleshed out in joint discussions involving either the Planning Subcommittee or Planning Advisory Committee. They contend that the RTO needs to more fully vet the policy and reliability implications of moving from one iteration of the queue process to the next.

Approved by FERC early this year (ER17-156), MISO’s new interconnection rules attempt to streamline an old process that was plagued by restudies and backlogs. (See FERC Accepts MISO’s 2nd Try on Queue Reform.) MISO Manager of Resource Interconnection Neil Shah said DPP studies coming out of the MISO West region are particularly heavy this year — “more than the current transmission system can accommodate” — and schedule delays are imminent. The RTO has so far this year received 85 requests representing nearly 12 GW of possible generation from that region alone.

“The most practical thing to do is to prepare for delays. It’s really unprecedented, and the complexity of the studies will increase. … We just want stakeholders to be aware of how much it’s going to take to study this amount of megawatts,” Shah said.

Staff argued against stakeholders that were looking to change an already agreed-upon DPP timeline.

“Let’s not beat this dead horse,” Brown said. “I think we’ve had those discussions before. It was really incumbent on the stakeholders to decide if they want to accept those risks, and they’ve agreed to those risks. Stakeholders preferred to get it started right away.” He added that discussion was laid to rest in IPTF meetings during the spring.

MISO will clear the February 2016 batch of projects from the first part of the DPP before submitting any of the August 2016 entrants, a process that stakeholders favored over merging the two groups together in order to initiate the studies earlier — even if the separated approach carries an increased risk of restudy.

Shah said stakeholders decided in spring to continue with the changeover schedule, which was initially filed with FERC.

“Based on the feedback that we’ve received so far, we’re going to continue the course on the original schedule,” he said.

Shah noted that the probability of delays is high, even without a current delay. MISO is putting more of its own resources toward the study effort, he said.

The RTO is adding an additional 14 engineers to the approximately 100-employee queue team to handle the influx of studies, according to Brown. Eight Siemens engineers are working on studies for the possible additions in the MISO West region alone.

“There’s much consternation and gnashing of teeth among my finance team right now,” Brown said. “We still think there are going to be delays no matter how many bodies we throw at it.”

Geronimo Energy’s Randy Porter applauded MISO for being able to complete its schedule of studies on time so far this year. “I’d like to copyright a term: ‘study-tsunami,’” he said.

Stakeholders asked if MISO will compare the high number of projects to anticipated load growth to see if the projects will realistically be built.

MISO “would take a step back and look at the comprehensive picture” in subsequent studies occurring further into the queue, Shah said.

July 24, 2017

PJM MRC/MC Preview

Below is a summary of the issues scheduled to be brought to a vote at the Markets and Reliability and Members committees Thursday. Each item is listed by agenda number, description and projected time of discussion, followed by a summary of the issue and links to prior coverage in RTO Insider.

RTO Insider will be in Wilmington, Del., covering the discussions and votes. See next Tuesday’s newsletter for a full report.

Markets and Reliability Committee

2. PJM Manuals (9:10-9:30)

Members will be asked to endorse the following proposed manual changes:

A. Manual 1: Control Center and Data Exchange Requirements. Revisions developed to comply with NERC reporting requirements. Transmission operators will be required to maintain certain data during outages, including bus voltages for all 345-kV stations or higher, and megawatt flows for tie lines and all lines 345 kV or higher.

B. Manual 11: Energy & Ancillary Services and Manual 18: PJM Capacity Market. Clarifies language on what is needed to qualify for exempt or bonus megawatts during performance assessment hours in PJM’s Capacity Performance construct. PJM says it needs certain data to determine how close generators follow its schedule. The data include values for economic minimum and maximum and emergency maximum.

3. Pseudo-tie Pro Forma (9:30-10:00)

Members will be asked to endorse proposed pseudo-tie agreements and Tariff and Operating Agreement revisions. The documents were developed to standardize pseudo-ties and minimize operating confusion. (See “OC Discusses Pro Forma Agreements for Pseudo-Ties, Dynamic Schedules,” PJM OC Briefs: July 11, 2017.)

4. Governing Document Revisions to the Limitation on Claims (10:00-10:10)

Members will be asked to endorse Tariff and Operating Agreement revisions to clarify the two-year limit on requests for billing adjustments.

5. PJM M14B and PJM Operating Agreement Updates – TEAC Redesign (10:10-10:30)

Members will be asked to endorse updates to Manual 14B: PJM Regional Transmission Process and the Operating Agreement reflecting the change from the annual, 12-month Regional Transmission Expansion Planning cycle to an overlapping 18-month cycle beginning each September. The window for short-term projects will expand from 30 to 60 days. (See “RTEP Cycle Revisions Approved,” PJM PC/TEAC Briefs: July 13, 2017.)

Members Committee

Consent Agenda (1:20-1:25)

Members will be asked to endorse:

B. Tariff revisions related to the interconnection process regarding the alternate queue and cost allocation for projects less than $5 million. (See PJM Considering Injection Rights for Demand Response.)

1. Regulation Revisions (1:25-1:45)

Members will be asked to endorse proposed Tariff and Operating Agreement revisions to regulation market rules on performance scores, clearing and settlements that were endorsed by the Regulation Market Issues Senior Task Force and the MRC. The revisions change the rate for substituting traditional RegA and fast-response RegD. (See PJM Regulation Compensation Changes Cleared over Opposition.)

2. Pseudo-tie Pro Forma (1:45-2:15)

— Rory D. Sweeney

July 24, 2017

Public Power Takes PJM Gripes to Congress

By Rich Heidorn Jr.

While PJM stakeholders were meeting last week to consider yet more changes to the Reliability Pricing Model, public power representatives took their case to Congress, telling the House Energy and Commerce Committee on Tuesday that they should be released from participating in the increasingly complicated capacity construct.

American Municipal Power and Old Dominion Electric Cooperative told the committee that FERC should allow public power utilities to fill their needs through bilateral contracts or self-supply instead forcing them to participate in mandatory capacity markets. AMP — which provides power supply and other services to 135 members in Delaware, Indiana, Kentucky, Maryland, Michigan, Ohio, Pennsylvania, Virginia and West Virginia — also complained that PJM’s Capacity Performance rules undervalue the company’s new hydropower facilities.

AMP Senior Vice President and General Counsel Lisa McAlister and ODEC CEO Jack Reasor testified along with representatives from independent power producers NextEra Energy and Calpine, utilities Public Service Enterprise Group and Duke Energy, and demand response provider EnerNOC.

The two-hour hearing, titled “Examining the State of the Electric Industry through Market Participant Perspectives,” covered many issues. Rep. John Shimkus (R-Ill.) and ranking member Frank Pallone (D-N.J.) said the testimony would help them decide whether the Federal Power Act is in need of revisions.

PSEG made a pitch for financial support for its New Jersey nuclear plants, which Calpine and NextEra strongly opposed. Duke asked for reforms to the Public Utility Regulatory Policies Act and a “shot clock” for regulatory approvals of pipelines and other infrastructure projects.

Former FERC Chairman Joseph Kelliher, now executive vice president for NextEra, also offered his company’s answers for the questions that Energy Secretary Rick Perry asked in commissioning a study of renewable resources’ effect on the reliability of the grid. It is market fundamentals — not public policies, he said — that are the primary drivers of “baseload” plant retirements, and there is “no evidence” that those retirements are threatening reliability.

No RTOs or ISOs were represented in the hearing. They will get their chance to speak before the committee in a second hearing on July 26. But PJM was invoked frequently, and generally not favorably.

PJM Capacity Market under Fire

McAlister’s 21-page written testimony — more than twice as long as any other witness’ — reiterated public power’s longstanding complaints with PJM’s capacity construct, calling it a “complex rules-driven administrative mechanism” that “relies on such distinctly non-market features as an artificial demand curve, price caps and minimum offer price requirements, and obstacles to competition from certain types of resources.

“RPM is a ‘market’ in name only,” she continued. “And, as time has gone on, fewer and fewer PJM market participants use that term to describe it.”

ODEC also criticized RPM, saying its experience “has been mixed at best.”

PJM reliability pricing model public power — Reasor | © *RTO Insider*

Reasor quoted from FERC’s April 2006 order approving RPM. “After [load-serving entities] have had the opportunity to procure capacity on their own, it is reasonable for PJM to procure capacity in an open auction at a time when further delay in procurement could jeopardize reliability,” FERC said, adding, “This, however, should be a last resort.”

Although the annual capacity procurement is still called the Base Residual Auction, “repeated and significant design changes have made RPM more complex and costly and have undermined the ability of load-serving entities to use their resources to meet their capacity obligations,” Reasor said.

The 2016 BRA was the first PJM capacity auction with no rule changes from the prior year, following 24 significant FERC filings to revise RPM between 2010 and 2016, Reasor said, quoting PJM. The last major change, the introduction of Capacity Performance, imposes “onerous performance requirements” on capacity resources, he said.

New Hydro Dissed by CP

McAlister also complained about CP, saying it undervalues the $3 billion AMP spent to install 300 MW of hydroelectric facilities on existing dams on the Ohio River because the projects cannot guarantee continuous, yearlong operation. “This is the case because AMP cannot control the river flows and cannot practically back up the hydroelectric plants with an alternative generation resource,” McAlister said. “In making PJM’s capacity construct less flexible, CP also has made it less capable of integrating the diversity of resources that may be an element of implementing important state policies.”

McAlister said PJM “needs a resource adequacy construct that is robust enough to withstand the effect of external events without the need to adopt another set of complex rule changes in response to each event.”

She and Reasor said LSEs should be permitted to fulfill most or all of their capacity needs through bilateral contracts, with the BRA relegated to a truly residual auction to fill any shortfalls. (See related story, PJM Stakeholders See Capacity Auction Flaws, Offer Solutions.)

As a “second-tier alternative,” McAlister said, public power’s ability to self-supply their own loads should be restored by reducing the role of the minimum offer price rule (MOPR).

Transmission Costs

AMP also complained about transmission costs, saying four of its members’ transmission zones have seen annual revenue requirements double or triple between 2009 and 2016.

AMP’s and ODEC’s complaints regarding the transmission owners’ handling of supplemental projects — those not required for compliance with PJM’s reliability, operational performance or economic criteria — prompted FERC last August to issue an order to show cause finding that the TOs’ procedures were not in compliance with FERC Order 890 (EL16-71).

FERC said the evidence indicated that some TOs are “identifying — and even taking steps toward developing — supplemental projects before providing any opportunity for stakeholders to participate in the development of those projects through the PJM [Regional Transmission Expansion Plan] process.”

The order resulted in a hiatus in a stakeholder initiative, the Transmission Replacement Processes Senior Task Force, pending the TOs’ response. Although the TOs insisted they are in compliance with Order 890, they proposed a Tariff amendment providing additional detail on supplemental projects. FERC didn’t rule on the TOs’ response before losing its quorum in February.

Stakeholders last month voted to end the hiatus, with task force meetings schedule to resume July 28. (See Load Blocks TO Effort to Delay PJM Tx-Replacement Talks.)

“AMP supports appropriate transmission infrastructure build-out to replace aging infrastructure,” McAlister told the House committee. “However, there needs to be more transparent transmission planning, equitable treatment, better oversight to ensure the most cost-effective and efficient grid expansion, and rates of return that reflect current economic conditions and risks.”

AMP asked Congress for “enhanced” oversight of FERC “to ensure that [the commission] is responsive to the real needs of consumers” by making low costs “a central part of the RTO mission, in addition to promoting electric system reliability.”

McAlister also said Congress should ensure that RTO governing boards “are truly representative and open [and] transparent” with open board meetings. While the boards of MISO, SPP, ERCOT and CAISO meet in open session, PJM’s board meets in private, as does ISO-NE’s and NYISO’s.

Nuclear Subsidies

The hearing also considered proponents and opponents of subsidizing nuclear plants. Tamara Linde, PSEG’s executive vice president and general counsel, repeated the company’s threat to retire its 3,500-MW Salem and Hope Creek nuclear plants in southern New Jersey. The plants, which are licensed until at least 2046, produce about 45% of the state’s electricity.

Linde said FERC should order PJM and other RTOs to “immediately” change their market rules to “preserve the diversity and resiliency of the nation’s electric generation resource mix.”

“Markets weren’t designed to drive to fuel diversity as an outcome, because fuel diversity in the generation fleet was always presumed,” she said.

Linde also said the U.S. nuclear supply chain should be considered “critical infrastructure, just as we regard our national highway system, electric grid and drinking water.”

Opposing nuclear subsidies were NextEra’s Kelliher and Calpine’s Steve Schleimer, senior vice president for government and regulatory affairs. Schleimer said competitive markets are threatened by both the zero-emission credits for nuclear plants in New York and Illinois, and New England states’ long-term procurement of renewables.

“If not addressed, out-of-market subsidies will undermine competition, investment will dry up, and these states will be back in the business of mandating when, where and what type of new generation will be built through long-term ratepayer guarantees, which is exactly the structure we moved away from several decades ago,” he said.

“A ‘hybrid’ market, where a state relies in part on the competitive wholesale electricity market to meet its resource needs, but also retains the right to select and subsidize preferred generation resource types to meet certain public policy goals, does not work and destroys all new competitive investment,” Schleimer said.

CAISO’s Lesson

He said the risk is playing out in CAISO, where he said the state’s “long-term contracting practices have decimated the competitive market.”

“It has led to the paradox that while retail rates are amongst the highest in the country as a result of these contracting mandates, wholesale prices are so low that the economic viability of the remaining generation that is dependent on competitive wholesale markets (generally existing conventional generation resources acquired or built when the market was competitive) is increasingly threatened.”

Alex Glenn, Duke’s senior vice president for state and federal regulatory legal support, had five requests to Congress, including swift confirmation of FERC nominees; the retention of the federal income tax deduction for interest expenses; “a reasonable ‘shot clock’ for actions on permit applications” for critical infrastructure projects; and a rewrite of PURPA to eliminate above-market must-take purchase obligations.

Glenn also said Congress should amend the SAFETY Act “to expressly include cyberattacks, and improve the process to obtain a security clearance so that we can increase the information-sharing capabilities between public and private entities.” Including cyberattacks under the third-party liability protections in the act would allow utilities and first responders to help recovery from an attack without the threat of “of protracted lawsuits in multiple jurisdictions,” he said.

In contrast to Duke’s lengthy wish list, Kenneth D. Schisler, vice president of regulatory affairs for EnerNOC, had only one request. Schisler thanked federal policymakers for removing market barriers to DR and said “it is vital” that FERC find a way to maintain competitive markets while respecting state policies. “Our only ask here today is that you continue to recognize demand response and its importance to our national energy strategy,” he said.