Page 1187 – RTO Insider

February 20, 2018

CAISO Board Elects New Leadership

By Jason Fordney

The CAISO Board of Governors last week enacted new governance policies and named Governor David Olsen as chairman. It also reviewed the ISO’s policy roadmap for 2018.

In a teleconferenced meeting Thursday, the board enacted a new process whereby governors will hold yearly elections for chair. The five-member board voted to replace sitting Chair Richard Maullin with Olsen, who was originally appointed to the board in 2012 by Gov. Jerry Brown.

Governor Angelina Galiteva said that with CAISO involved in more regional matters and the Western Energy Imbalance Market (EIM), the board felt members should have the opportunity to participate as chairs and share some of the growing workload. The board went through an analysis to study best practices, she said.

CAISO board of governors — Galiteva (left) and Ferron | © *RTO Insider*

“This is something we thought over and talked about for quite a while,” Galiteva said. The board elected her to the newly created position of vice chair, nominated by Governor Mark Ferron and seconded by Governor Ashutosh Bhagwat.

“We are entering a period where there could be some rapid change we are part of or instrumental for,” Maullin said, as other board members thanked him for his service in his role. Maullin’s term on the board ended Dec. 31, and he said remaining on the board depends on the California State Senate, which confirmed him as chair in July 2015. He was reappointed by Brown in January 2015.

Cook Briefs Board on 2018 Roadmap

CAISO Director of Market and Infrastructure Policy Greg Cook briefed the board on the 2018 Policy Initiatives Roadmap and Annual Plan, saying the presentation to the board represents the final step in the implementation process.

In January, Cook briefed the EIM Governing Body on the plan, which includes a proposal to extend the ISO’s day-ahead market to the EIM. (See CAISO Plan Extends Day-Ahead Market to EIM.) Each balancing authority area would retain reliability responsibility, and states would retain control over integrated resource planning. Transmission planning and investment remains with each BAA and local regulatory authority.

Cook shared some of the tasks associated with the day-ahead market extension, including the alignment of transmission access charge paradigms to ensure EIM entities recover transmission costs consistent with the existing bilateral network, and consistent billing determinants across the day-ahead market footprint for market efficiency. There will also be distribution of congestion rents collected through the day-ahead market and a day-ahead resource sufficiency evaluation, among other requirements.

CAISO board of governors keith casey — Casey | © *RTO Insider*

Keith Casey, the ISO’s vice president of market and infrastructure development, told the board that implementing the day-ahead across the EIM will provide additional benefits, but it “certainly will fall short of the full benefits we would get with full participation under a regional construct.” These would include efficiency of a single balancing authority over a larger footprint, as well as transmission planning and resource adequacy benefits.

“We believe it has important benefits … but I do want to stress it will fall short of the full integration benefits,” Casey said.

PG&E Continues Criticism of RMRs

During a public comment period, Eric Eisenman, director of ISO relations and FERC policy for Pacific Gas and Electric, told the board that PG&E has no issue with anything in the roadmap but that addressing the increasing use of reliability-must-run designations (RMRs) and the capacity procurement mechanism (CPM) is the utility’s “highest priority.” He reminded the board of the “robust discussion” it had over RMRs at its November meeting when the designation of the gas-fired Metcalf Energy Center was approved. (See Board Decisions Highlight Market Problems.)

CAISO board of governors David Olsen — The CAISO Board of Governors and others at the November meeting in Folsom, California | © *RTO Insider*

“PG&E continues to be very concerned about a slew of RMRs for 2019 that would be designated later this year,” Eisenman said. “But at this point, we just don’t know what is going to happen.” He urged CAISO to implement more extensive “Phase 2” changes in its RMR/CPM initiative in time for 2019 designations. The ISO has indicated it only intends to address must-offer requirements for RMR and CPM units in that time frame.

Casey said the ISO is looking at transmission alternatives to prevent situations that might otherwise lead to RMRs, including working with PG&E to address “low-hanging, fast upgrades” in the subarea where the Metcalf plant sits. The improvements would alleviate about 600 MW of local capacity requirements and are included in a transmission plan due to be finalized in March, he said.

“There is much we can do — we have a great deal of flexibility with the transmission plans to do those types of studies,” but it would be challenging to complete the improvements by fall 2019, he said.

“We share PG&E’s urgency about getting after these RMR reforms,” Casey said.

CAISO is in the midst of developing a package of enhancements to the RMR/CPM process, which is proving to be a contentious proposal among market stakeholders. (See CAISO, Stakeholders Debate RMR Revisions.)

February 20, 2018

FERC Approves EIM Changes, Western Measures

By Jason Fordney

FERC on Thursday approved a package of modifications to improve market efficiency developed by CAISO for the Western Energy Imbalance Market (EIM). It also issued several other decisions related to Western states and energy markets.

The commission said the EIM measures would improve efficiency by automating manual processes, providing greater transparency into bilateral transactions and enabling increased participation in both the EIM and CAISO.

The approved changes include automated matching of import/export schedule changes between resources inside and outside the EIM, as well as the ability to automate changes to mirror system resources at intertie scheduling points between CAISO and an EIM entity (ER18-461).

“We find that the automated matching and the automatic mirroring functionalities will result in more efficient EIM market outcomes by automating manual processes that are prone to errors and better maintain balance between resources and load following intertie schedule changes,” FERC said.

The EIM Governing Body approved the package of market changes in November 2017 | © *RTO Insider*

The EIM Governing Body approved the package of changes in November, after CAISO had scaled down the initiative based on consultations with stakeholders. (See EIM Governing Body Approves ‘Consolidated’ Initiatives.) The changes also facilitate bilateral settlements and improve the market’s modeling accuracy by expanding the functions of non-generator resources.

CAISO had requested approval of the measures by Feb. 15 to allow for the participation of Powerex and Idaho Power in the EIM on April 4.

Deseret Earns MBR Authority

The commission last week also approved Deseret Generation & Transmission Co-operative’s updated market power analysis for the Northwest region, granting the utility market-based rate authority effective Sept. 12, 2016. Utah-based Deseret became a public utility in 1996 after paying off its debt related to rural utility service (ER16-2186).

Deseret owns the 458-MW Bonanza coal-fired plant and a 25% interest in the 430-MW Hunter 2 coal-fired unit, both in the PacifiCorp balancing authority area.

FERC Approves PG&E/Port of Oakland Agreement

The commission also approved an interconnection agreement between Pacific Gas and Electric and the Port of Oakland but suspended the agreement and subjected it to hearing and settlement judge procedures (ER17-2536).

FERC EIM Energy Imbalance Market Gridliance — The Port of Oakland is a major container shipping facility and a municipal electric supplier.

The port acts a municipal electricity supplier that serves customers located at the Oakland International Airport, which it owns and operates, using PG&E’s transmission and distribution facilities.

Last year, the port submitted an application to convert its Cuthbertson substation from retail service to wholesale interconnection service under PG&E’s transmission owner tariff, but PG&E identified an issue with the tariff based on the substation’s power factor, which it said has to be resolved before it can provide wholesale service.

The port contends that PG&E’s sales for resale to it are subject to FERC jurisdiction and that it is concerned about provisions in the interconnection agreement referring to matters under the jurisdiction of the California Public Utilities Commission. The port argues that PG&E is attempting to “improperly impose” CPUC-jurisdictional exit fees on it and protests language describing the change to wholesale service as a notice of departure from PG&E, subjecting the port to departing load fees.

The port also contests that certain aspects of the agreement are unreasonable and unduly discriminatory compared with other PG&E interconnection agreements.

FERC set a public hearing subject to settlement procedures to be held within 15 days.

GridLiance Rehearing Request Rejected

FERC rejected GridLiance West’s rehearing request contending the commission erred when it failed to approve the company’s proposed use of an actual capital structure related to incentive rates for facilities it sought to acquire from Valley Electric Transmission Association (ER17-706). GridLiance West said the proposed capital structure was comparable to similarly situated transmission companies.

In its order denying rehearing, the commission said it made no final determination regarding the proposed capital structure but “found that its preliminary analysis indicated that the proposed TO Tariff had not been shown to be just and reasonable and raised issues of material fact that could not be resolved on the record before the commission.”

Idaho Commission Complaint Headed to Court?

FERC also declined to act on a petition for enforcement filed by Franklin Energy Storage against the Idaho Public Utilities Commission (EL18-50, et al.). The company argued the state commission had improperly classified its energy storage facilities as solar qualifying facilities, preventing them from being eligible for the PUC’s stated electricity rate under the Public Utility Regulatory Policies Act. The rate is available to non-wind and non-solar QFs of an average capacity of 10 MW or less.

The decision will allow the company to bring an enforcement action against the Idaho commission in the appropriate court, FERC said.

February 20, 2018

FERC Grants Deadline Waiver for New Hampshire Generator

By Michael Kuser

FERC on Thursday granted a waiver request from Public Service Company of New Hampshire (PSNH), allowing ISO-NE to accept its restoration plan for the Lost Nation generating unit, which the company submitted one business day after the deadline under the RTO’s Tariff (ER18-465).

Eversource Energy, PSNH’s parent company, in January completed the sale of its fossil-fuel generation units in New Hampshire to Granite Shore Power.

On Oct. 20, ISO-NE flagged the oil-fired combustion turbine in Groveton, N.H., for having a significant decrease in capacity below its cleared capacity supply obligation (CSO) of 13.97 MW for the RTO’s 2018-2019 capacity commitment period.

FERC ISO-NE waiver request PSNH — Covered bridge over the Upper Ammonoosuc River next to the 18-MW Lost Nation plant in Groveton, NH.

Under the rules governing the RTO’s annual reconfiguration auctions, Lost Nation had 10 business days to either purchase additional capacity to replace the shortfall or submit a restoration plan showing how it would be able to meet its obligation.

PSNH said the decrease in capacity occurred because a summer seasonal claimed capability audit was not performed. An Eversource employee intended to file a restoration plan showing that Lost Nation was dispatched four days in September 2017 and thus should be capable of supplying output to meet its awarded CSO.

The utility said that two events caused the delay in submitting the restoration plan.

First, the mother of the employee charged with submitting the plan died on Oct. 29, 2017, while the plan was out for review. Then, after a strong storm tore through the state on Oct. 30, the employee was called to storm duty and performed three consecutive 13-hour shifts until being released on Nov. 2. He was then given leave to prepare for his mother’s Nov. 4 memorial service.

The combination of events distracted the employee from submitting the restoration plan by the close of the Friday, Nov. 3 submission window; he submitted the plan the morning of Monday, Nov. 6. The RTO said it could not unilaterally waive the Tariff-imposed deadline.

In its Feb. 15 decision, the commission found that “PSNH acted in good faith by submitting the restoration plan as soon as possible after it discovered the omission.” The commission also noted that PSNH’s waiver request was uncontested.

February 20, 2018

FERC: NYISO Not Done on Order 1000 Rules

By Michael Kuser

FERC ruled Thursday that NYISO must make additional changes to comply with Order 1000, while acknowledging in a separate docket that it erred in directing the ISO to change the indemnification language in its pro forma development agreement.

The commission said transmission developers must indemnify NYISO except for acts of “gross negligence or intentional misconduct.” In ordering NYISO to remove the word “gross” from the agreement, the commission said it failed to follow its precedent in a 2015 order involving MISO (ER15-2059-002; ER13-102-008).

NYISO FERC FERC Order 1000 compliance — | *NYSEG*

FERC also granted NYISO a request for clarification, saying it will allow the ISO to propose a new process for evaluating alternative regulated transmission solutions and regulated backstop solutions for interconnection. The ISO’s current process is outlined in Tariff Attachments X and S.

But the commission rejected rehearing requests by the New York Transmission Owners (NYTOs), who balked at the commission’s requirement that TOs responsible for providing “backstop” solutions to a reliability need — normally the incumbent TO — sign the development agreement, as is required of nonincumbent transmission developers.

“If responsible transmission owners developing regulated backstop solutions are not required to execute a development agreement, they will have an advantage over nonincumbent transmission developers both in seeking selection in the regional transmission plan for purposes of cost allocation and remaining selected,” the commission said, noting that the NYISO Transmission Owners Agreement and the agreement between NYISO and the NYTOs on the Comprehensive Planning Process for Reliability Needs are less stringent than those in the development agreement

The NYTOs consist of Central Hudson Gas & Electric; Consolidated Edison; New York Power Authority; New York State Electric and Gas; Niagara Mohawk Power; Long Island Power Authority; Rochester Gas & Electric; and Orange and Rockland Utilities.

Compliance Filings

FERC also provided its clarification on alternatives to Attachments X and S in a concurrently issued order in which it accepted in part Order 1000 compliance filings NYISO made in March and September 2016. The commission accepted most of the ISO’s Tariff revisions but rejected language it said was discriminatory or unjust (ER13-102, et al.).

It ordered the ISO to make changes in its proposed transmission interconnection procedures that it found unjust and unreasonable, including language on scheduling and definitions.

It also required the ISO to make changes in its proposed Operating Agreement regarding maintenance schedules, compliance with local reliability rules and investigations of equipment malfunctions.

The commission found “incorrect” the Tariff revision that said nothing in Attachment Y affects a TO’s right to recover the costs of upgrades to its facilities regardless of whether the upgrade has been selected in the regional transmission plan for purposes of cost allocation.

“Pursuant to Order No. 1000, once NYISO selects a transmission project in the regional transmission plan for purposes of cost allocation, the regional cost allocation method set forth in Attachment Y of the [Tariff] applies, unless the project developer ‘decline[s] to pursue regional cost allocation,’” the commission said.

February 18, 2018

PJM Markets and Reliability Committee Preview: Feb. 22, 2018

Below is a summary of the issues scheduled to be brought to a vote at the PJM Markets and Reliability Committee on Thursday. (The scheduled Members Committee meeting was canceled.) 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 2: Transmission Service Request. Revisions developed to align manual with Tariff changes endorsed at the Dec. 21 meeting to revise the process for analyzing transmission service requests. The initial study is replaced by the firm transmission feasibility study.

B. Manual 11: Energy & Ancillary Services. Clarifies the energy-offer verification process for demand-side bids, including caps on price-sensitive demand bids; reverses prior change to pre-emergency and emergency demand response because they are outside the scope of FERC Order 831.

C. Manual 14D: Generator Operational Requirements. Clarifies information requirements and submission deadlines for generation transfers. (See “Owner Transfer Rules Revision,” PJM Operating Committee Briefs: Dec. 12, 2017.)

D. Manual 18: PJM Capacity Market. Revisions developed in response to a FERC order on rules for pseudo-tie requirements and a transition period for existing pseudo-ties (ER17-1138). (See FERC OKs Change to MISO, PJM Pseudo-Tie Rules.)

3. Tariff Revisions to Address Overlapping Congestion (9:30-9:45)

Members will be asked to endorse proposed Tariff and Operating Agreement changes to address overlapping congestion. PJM and MISO have been working to remove duplicative congestion charges and have developed a two-phase plan to eliminate them. These changes encompass the second phase. (See MISO, PJM Pursue Pseudo-Tie Double-Charge Relief.)

4. Summer-Only Demand Response Senior Task Force Charter (SODRSTF) (9:45-9:55)

Members will be asked to endorse a draft charter for the SODRSTF. The task force, which was developed to consider ways to take advantage of excess summer-only resources, has met several times. (See Stakeholders Seek Load Discussion in PJM DR Task Force.)

5. Sunsetting Senior Task Forces (9:55-10:15)

Members will be asked to sunset the Underperformance Risk Management Senior Task Force (URMSTF) and the Regulation Market Issues Senior Task Force (RMISTF). The URMSTF developed proposals on underperformance risk management, which failed to receive MRC stakeholder endorsement, and changes to external capacity performance requirements, which were endorsed. The RMISTF resulted in a new regulation signal being implemented, along with a package of regulation procedure and requirement changes. (See PJM Regulation Compensation Changes Cleared over Opposition.)

— Rory D. Sweeney

February 18, 2018

FERC OKs MISO Queue Changes, Orders Fewer Restudies

By Amanda Durish Cook

FERC last week accepted several small revisions to MISO’s new interconnection queue design but also told the RTO it must keep working to ensure it sticks to a commitment to reduce restudies.

The commission provided MISO a month to revise its Tariff to eliminate a practice of automatically conducting a restudy based on predetermined triggers, which include a project’s termination or the withdrawal of a project from the queue (ER17-156-002).

MISO FERC interconnection queue — | *MISO*

“In the October 2016 queue reform filing, MISO proposed that, instead of conducting a restudy automatically upon each occurrence of a restudy trigger, the RTO would re-evaluate the need for any common use or shared network upgrades associated with the project,” FERC said.

MISO FERC interconnection queue design — As of Nov. 2017 | *MISO*

FERC largely accepted MISO’s new, three-stage interconnection queue in January 2017, but it sought more detail on a few aspects of the plan, prompting a follow-up filing. (See FERC Accepts MISO’s 2nd Try on Queue Reform.) The commission at the time directed MISO to conduct restudies on an as-needed basis only, even when a triggering event occurs. It said the RTO “could decide in its discretion whether a restudy was needed or not.”

In revisions filed last March, MISO altered its Tariff to enable it to conduct restudies for reasons other than triggering events. In the most recent ruling, FERC reversed that move, saying the RTO cannot conduct a restudy absent a trigger.

FERC accepted several other smaller Tariff revisions that it had directed MISO to make, including:

Stipulating mandatory attendance of transmission owners in scoping-level meetings between MISO staff and interconnection customers;
Describing the types of events that trigger a queue restudy; and
Offering customers a provisional generator interconnection agreement option at any time in the interconnection process, regardless of whether MISO failed to meet a study deadline.

MISO was also required to scale back its site control requirement by the queue’s second decision point from 100% to 75% after FERC determined that complete site control is difficult to obtain so early in the process.

The RTO also had to clarify that an interconnection customer that withdraws early in the queue — at either the first or second decision points — will not be responsible for the costs of other customers’ interconnection studies, and that a customer withdrawing at the third decision point should only pay a study deposit fee to cover a potential restudy for another interconnection customer.

Finally, MISO added language to clarify that the batch of projects entering the definitive planning phase in August 2015 was grandfathered into the old queue design.

However, FERC’s recent ruling gave the RTO 30 days to clarify that the queue’s third and fourth $4,000/MW milestone payment collection is only an initial charge subject to change as costs become clearer in the study process.

“This language implies that the M3 and M4 milestone payments are set to $4,000/MW and are not subject to a true-up as more accurate estimates become available, which is not in line with MISO’s indication in its testimony,” FERC said.

In accepting MISO’s filing, FERC dismissed a bundle of complaints from EDF Renewable Energy as being outside the scope of the proceeding. EDF had asked FERC to force MISO to share more network modeling details and prescribe “remedies” should the RTO fail to complete studies on time. The company also sought a directive instructing MISO to develop a fast-track queue option for vetted projects, and complained that the RTO failed to coordinate its generator interconnection process with the transmission planning process.

Another EDF complaint against MISO’s new queue design is still outstanding. (See Renewables Developer Escalates MISO Queue Design Dispute.)

February 18, 2018

Mass. Picks Avangrid Project as Northern Pass Backup

By Michael Kuser

Avangrid announced Friday that Massachusetts has selected the transmission project of its subsidiary, Central Maine Power, as the alternative for the state’s 9.45-TWh clean energy solicitation if New Hampshire regulators do not approve the Northern Pass transmission line by March 27.

Massachusetts awarded the contract to Eversource Energy and Hydro-Quebec’s Northern Pass on Jan. 25, only to see the New Hampshire Site Evaluation Committee (SEC) unanimously reject the 1,090-MW transmission project a week later. Eversource appealed the decision, saying in a statement Feb. 16: “We have a strong legal argument for a reconsideration by the SEC.” (See New Hampshire Rejects Permit for Northern Pass.)

Avangrid Northern Pass Hydropower — | *Eversource, Central Maine Power*

CMP and Hydro-Quebec’s New England Clean Energy Connect (NECEC) transmission project would deliver up to 1,200 MW of Canadian hydropower to the New England grid via a 145-mile transmission line. The partners estimate the project to cost $950 million.

News of the selection drew a protesting tweet from Dan Dolan, president of the New England Power Generators Association: “Massachusetts is now all-in on Hydro-Quebec, going from the fatally flawed Northern Pass to a Maine project that still lacks virtually all its key permits. Hydro-Quebec is asking for Massachusetts consumers to guarantee them revenue through an above-market contract for electricity for the next two decades.”

Dolan said existing power plant operators in the region have invested more than $13 billion in their plants without any guarantee of cost recovery or profit.

Beginning Negotiations

CMP submitted applications for state and federal permits for NECEC in mid-2017 and said it expects to receive state approvals later this year and final federal permits in early 2019. The company said it will immediately begin negotiation of long-term contracts with the Massachusetts electric distribution companies to prepare for a submission to the state’s Department of Public Utilities in April 2018.

“Our applications for state and federal permits are moving forward with the strong support of communities and stakeholders in Maine,” CMP CEO Doug Herling said in a statement.

Eversource’s statement said that Friday’s decision “strikes a sensible balance by allowing negotiations with Northern Pass to continue, while establishing a back-up protocol that can be initiated if necessary.”

Avangrid Networks CEO Bob Kump said, “A new transmission link between Maine and Quebec would deliver a reliable, firm supply of clean energy to help dampen seasonal price instability when high demand puts pressure on natural gas supplies.”

Massachusetts issued its MA 83D solicitation for hydro and Class I renewables (wind, solar or energy storage) last July. The selection committee for the clean energy request for proposals issued in July 2017 includes representatives from the state’s Department of Energy Resources and from distribution utilities Eversource, National Grid and Avangrid subsidiary Unitil.

Any contract awarded under the request for proposals must be negotiated by March 27 and submitted to the DPU by April 25.

Other proposals for the RFP included Nova Scotia-based Emera’s Atlantic Link project, a 375-mile submarine HVDC transmission line from New Brunswick to Plymouth, Mass., to deliver 5.69 TWh of clean energy per year. National Grid partnered with Citizens Energy on two transmission projects; one of them, the Granite State Power Link, is a 59-mile HVDC line from northern Vermont to New Hampshire to deliver 1,200 MW of new wind power from Canada.

The state-owned Hydro-Quebec also partnered separately with Transmission Developers Inc. for the RFP and, as with Northern Pass, made two proposals, one pure hydro and one with a wind energy component.

February 18, 2018

Michigan Dam Ordered Shut over Safety Breaches

By Amanda Durish Cook

FERC last week ordered the shutdown of a Michigan hydroelectric project over longtime safety violations — the most significant of which relate to inadequate spillway capacity.

The commission will revoke the license for Boyce Hydro’s 4.8-MW Edenville Dam in northern Michigan on March 1 following its Feb. 15 cease generation order and denial of the company’s request for rehearing on the issue (10808-058).

FERC dismissed Boyce’s arguments that the commission didn’t consider corrective measures the dam had already taken; that it doesn’t have authority to order a dam to shut down; and that the cease generation order was arbitrary and capricious. FERC has been threatening to close Edenville since late last spring.

The commission last month gave Boyce until March 1 to correct violations, some of which that have persisted since 2004, including:

Failing to increase spillway capacity to address the increased likelihood of more frequent flooding;
Performing unauthorized dam repairs and excavation;
Neglecting to file a public safety plan or follow its own water monitoring plan; and
Failing to acquire all property rights and to construct required recreation facilities near the dam.

FERC has repeatedly told Boyce to construct two auxiliary spillways to reduce the risk of flooding, “a grave danger to the public,” the commission wrote.

“Boyce Hydro’s license includes terms and conditions concerning dam safety, property rights, water quality, public recreation and safety, and other areas of public concern,” the commission said. “Boyce Hydro has a long history of noncompliance with those terms and conditions … [and] failed to comply … except for the obligations to acquire and document certain property rights (although the lack of designs for the new and revised spillways makes it difficult to determine if it has acquired all necessary property rights).”

FERC hydropower Edenville Dam Boyce Hydro safety violations — Edenville Dam spillway

The commission in January granted Boyce a temporary stay of shutdown until the beginning of March so the company can use the dam’s powerhouse to pass flows to alleviate ice formation on spillway gates during winter. (See Michigan Dam Faces Shutdown over Longtime Safety Concerns.)

FERC said Edenville’s current spillway can only currently handle 50% of a probable maximum flood.

The commission ordered Boyce last year to file plans to construct spillways and provide public access and recreational facilities by late 2017, but the filings never materialized, it said. Although Boyce had hired an engineering firm to design a new spillway and promised to create an escrow account for 50% of its gross revenues to fund construction, FERC found those plans insufficient, saying that it would take the company two years to save enough money to fund spillway construction.

“Given that the public has already been at risk for more than 13 years due to the licensee’s refusal to remediate the project spillways, we cannot accept a proposal that will perpetuate the problem even longer,” FERC said.

The commission expressed disbelief that Boyce’s lengthy history of noncooperation would change now.

“After weighing the relevant factors, commission staff determined that the violations required prompt action and that the licensee’s persistent pattern of noncompliance provided strong evidence that it would not make serious efforts to come into compliance absent an order disrupting its operation,” the commission wrote.

FERC said it didn’t take the economic impacts of a shutdown lightly but said the move is “a situation of Boyce Hydro’s own making.”

Boyce can seek a rehearing of the order before a FERC administrative law judge within 30 days.

February 18, 2018

Trade Group Seeks Expanded DR Measures in MISO

By Amanda Durish Cook

A distributed energy resource trade group is calling on MISO to open its markets to customer-owned demand response and urging state regulators and utilities to develop programs that reimburse small DR providers.

The Advanced Energy Management Alliance (AEMA) last week issued a white paper containing model Tariff language intended to extend access to MISO’s wholesale markets to customer-owned demand-side resources.

The white paper suggests that states in the RTO’s footprint adopt DR programs like those in New York and the portion of Indiana in PJM.

MISO AEMA Demand Response Hydropower — | *Advanced Energy Management Alliance*

“While not new to the Midwest, the growth and development of demand response in the region has largely stagnated,” AEMA wrote. “To create shared value for utilities and consumers, states should take near-term action to create robust demand response programs where demand response is lacking and evolve demand response program design in territories that have had the same tariffs for over a decade.”

Like in the PJM area of Indiana, AEMA suggests having utility-qualified DR providers register their customers with a utility, which would then enroll the customers in MISO’s DR program. The utility would receive capacity credit for customers they enroll, and DR providers would get either an average price from MISO’s annual capacity auction or 35% of the net cost of new entry. AEMA said the approach would be “an effective means for stimulating cost-effective DR while working within existing state and MISO market constructs.”

As an alternative, AEMA said MISO could adopt New York-style programs that concentrate on reducing transmission and distribution costs and stay independent of wholesale capacity programs.

The organization also said that if states agree, MISO could devise Tariff rules for peak load management, distribution-level services and, eventually, additional wholesale market programs.

AEMA also suggested that Midwestern states allow bilateral contracting between utilities and DR providers. Under this scenario, the utility and the provider contract for a specific number of megawatts for enrollment, a price per megawatt and program design — including the terms of dispatch.

“AEMA is eager to collaborate with MISO-based utilities, regulators and system operators in this endeavor. Our goal is not to overturn existing bans that prohibit demand response providers from directly enrolling customers in wholesale market programs, but instead to develop new creative approaches to exploiting the full potential of demand response,” the group said.

It said new DR resources are less expensive than running aging generation.

“Energy leaders in the Midwest should not let excess capacity stop them from pursuing all cost-effective demand response,” the organization said.

AEMA Executive Director Katherine Hamilton said the white paper is a “roadmap” for state regulators and utilities.

“We hope that this white paper is used as intended — to inform and offer options for regulators and utilities seeking to partner with third-party providers and consumers. AEMA members seek to grow our businesses while giving consumers additional choices and providing cost-effective, environmentally sustainable services to the electric grid,” Hamilton said.

Several utilities in MISO states have interruptible DR programs, but AEMA said those programs need to evolve.

MISO had 10.7 GW of wholesale DR capacity in 2016, 8.9% of its annual load peak. The RTO’s DR is mostly derived from interruptible load and behind-the-meter generation under state-regulated and utility-run programs and accredited as load-modifying resources or emergency demand resources.

February 18, 2018

ITC Subsidiary Gets OK to Buy Michigan Tx Assets

FERC last week authorized an ITC Holdings subsidiary to purchase transmission assets from a small southwestern Michigan city.

The ruling authorizes Michigan Electric Transmission Co. to spend $201,206 to buy transmission assets at the Black River Substation from the City of Holland Board of Public Works (EC18-21). The assets include surge arrestors, relay panels, circuit breakers, backup relays and disconnect switches that Michigan Electric plans to use in its transmission operations.

Transmission assets FERC ISO-NE ITC Holdings Holland Michigan — ITC transmission | *ITC*

The commission said the acquisition was consistent with the public interest and won’t hinder competition in the area. Michigan Electric has also pledged to hold all transmission customers harmless from any transaction costs for five years.

“The proposed transaction does not involve any change in ownership or control of any generating facilities. Accordingly, the proposed transaction will not have any impact on concentration in any relevant market,” FERC said. The commission also said that prior experience suggests that sales involving only the transfer of transmission facilities are unlikely to result in uncompetitive activity.

— Amanda Durish Cook