Page 1251 – RTO Insider

October 23, 2017

Good Markets, Bad Markets: CEOs Sound off on State Policies

By Rich Heidorn Jr.

WASHINGTON — Panelists at the Energy Bar Association’s Mid-Year Energy Forum last week heard two very different views of the health of wholesale markets.

wholesale markets eba energy bar association — Flexon | © *RTO Insider*

Pacific Power CEO Stefan Bird was effusive in his praise of the Western Energy Imbalance Market (EIM), which saved parent company PacifiCorp almost $9 million in the second quarter of 2017. But Dynegy CEO Robert Flexon complained that CAISO and NYISO had become increasingly inhospitable to merchant generators because of state policies favoring renewables and nuclear generation, respectively.

“For us, the markets are [in an] incredibly fragile situation. California is a disaster. There isn’t any competitive power company out there who wants to put a nickel into California,” he said.

Flexon also bemoaned MISO Zone 4 in Southern Illinois, where he said competitive units face unfair competition from rate-based generation. The state also has approved zero-emission credits for nuclear plants, leading to fears in PJM — whose footprint includes Northern Illinois — that such subsidies will be contagious.

“PJM is doing everything they can to try to keep their market together. They’re very proactive,” Flexon said. “They’re trying to fix price formation and the like. [Having] half our megawatts in PJM, I feel good about that.” (See related story, PJM: Energy Price Formation Addresses DOE NOPR.)

Bird said his company’s experience with the EIM has been an unquestioned success.

Moderator Christopher R. Jones, a partner with Troutman Sanders, had set off the discussion by asking Bird if the markets are “healthy.”

“Are they enabling what our customers want? Are they enabling [a] low-cost, affordable, reliable future? I think the answer is resoundingly ‘yes,’” said Bird, whose company has 740,000 customers in Oregon, Washington and California.

“We’ve really had unprecedented opportunities to move that dial on a very accelerated pace and lower costs as well as reduce emissions.”

He said the EIM’s economic dispatch and its ability to move renewable power to load centers enabled PacifiCorp to announce in June a $3.5 billion investment in renewables and transmission in Wyoming, Utah and Idaho “at very little to no costs for our customers and savings over the long term.” (See PacifiCorp IRP Sees More Renewables, Less Coal.)

John DiStasio, president of the Large Public Power Council, said his members don’t have a single view of the market. His organization, which represents the 26 largest members of American Public Power Association, has members in NYISO, SPP and ERCOT.

“Those members that view that there’s economic benefits for them are participating in markets, and those who don’t see that don’t [participate],” DiStasio said.

He said RTOs have gone through “identity crises.”

“When we started up with CAISO, it was really a traditional RTO. And at some point, state policy started to drive how they looked at supporting environmental policy as well. There’s been hit and miss on how that’s been priced. There’s been hit and miss on how you get the right incentives for capacity in some of the markets.” DiStasio said California’s dominance of CAISO has been a barrier to greater market expansion in the West.

“Having said that … moving energy over wider regions I think is going to have a certain inevitability to it where we’ll have more and more people operating in markets — even if it’s just at the EIM level.

“From a Western perspective, I was appreciative that FERC didn’t try to push the Energy Imbalance Market. Actually, it would have fallen apart had that happened given the history of the [2000-2001] energy crisis, the [1980 Pacific Northwest Electric Power Planning and Conservation Act], given what happened in the Northwest during the energy crisis. I think FERC trying to assert more control at that time actually would have had a negative effect. Now, the market dynamics seem to have emerged organically enough that you have people that are voluntarily creating critical mass.

“I think this is really going to be a delicate balance going forward with how much does FERC push on state policy, and I think they may have to rethink the whole paradigm at some point. Because it is a clearly a hybrid and we’re kind of stuck … in no man’s land.”

When the discussion turned to Energy Secretary Rick Perry’s call for price supports for coal and nuclear plants, Flexon also called for FERC action.

“FERC has been missing while all the mischief has been happening,” he said, referring to the agency’s six months without a quorum. “They need to get back in the game and protect the markets they created.”

October 23, 2017

FERC Seeks Cyber Controls on Portable Devices; Sets GMD Plans

By Rich Heidorn Jr.

WASHINGTON — FERC on Thursday proposed rules to prevent malware from infecting “low impact” computer systems through transient electronic devices such as laptops and thumb drives.

FERC NOPR GMDs cybersecurity — | © *RTO Insider*

The Notice of Proposed Rulemaking would approve critical infrastructure protection reliability standard CIP-003-7, a response to an order issued by FERC in January 2016 (RM17-11). (See FERC Postpones Action on Supply Chain Protections.)

In addition to setting controls on devices frequently connected and disconnected from low-impact Bulk Electric System (BES) facilities, the NOPR also requires such facilities to have a policy for declaring and responding to “exceptional circumstances.”

High- and medium-impact BES cyber systems already have rules for responding to “exceptional circumstances,” which include situations that impact BES reliability or pose the risk of injury or death and cybersecurity incidents requiring emergency assistance.

The NOPR also directs NERC to revise the standard to provide objective criteria for electronic access controls for low-impact systems and add ways to mitigate the risk of malicious code introduced by third-party transient electronic devices, such as scanning devices prior to use.

GMD Order

In a separate order, FERC approved NERC’s preliminary geomagnetic disturbance (GMD) research work plan and ordered it to file a final plan within six months (RM15-11-002).

NERC’s GMD work plan, which it developed in collaboration with the Electric Power Research Institute and its GMD Task Force, identified nine research areas and sets an estimated time frame for their completion. It was developed in response to the commission’s September 2016 order requiring grid operators to assess and protect against the threat of GMDs. (See FERC Approves GMD Reliability Standard.)

Thursday’s order sets the priority in which NERC should conduct the GMD research, saying it should first seek to improve earth conductivity models for studies of geomagnetically induced currents. The commission cited the models’ importance in completing the GMD vulnerability assessments required by reliability standard TPL-007-1.

It said the second priority should be improving harmonics analysis “because the synergistic effects of harmonics during GMD events are not well understood.”

October 23, 2017

‘Momentum’ Seen for U.S. Offshore Wind

By Rich Heidorn Jr.

WASHINGTON — Even as the Trump administration has rejected the Paris Agreement and works to boost coal-fired generation, optimism has been building on the East Coast for the offshore wind industry.

The U.S. market has gained momentum in the last two years, the head of DONG Energy Wind Power U.S. told the Energy Bar Association’s Mid-Year Energy Forum during a panel discussion last week.

energy bar association eba offshore wind — Brostrøm | © *RTO Insider*

President Thomas Brostrøm credited state renewable portfolio standards and carbon reduction goals for creating demand. And he said the shallow waters off the East Coast provide attractive sites like those in Europe.

DONG, the No. 1 offshore wind generator in the world, clearly sees renewables as the future. On Oct. 30, it will ask shareholders to approve changing its name — originally an abbreviation for Danish Oil and Natural Gas — to reflect its commitment to renewable power. It completed the divestiture of its upstream oil and gas business in September. The new name, Ørsted, honors Danish scientist Hans Christian Ørsted, who is credited with discovering electromagnetism in 1820.

The company, which operates more than 1,000 offshore wind turbines in Europe, acquired the rights to develop more than 1,000 MW off New Jersey and is working on a pilot project with Dominion Energy off Virginia. (See Dominion Plans 12-MW Offshore Wind Project, 2nd in US.) It also has formed a joint venture with Eversource Energy to bid on Massachusetts’ solicitation for 1,600 MW of offshore wind.

energy bar association offshore wind eba — Kalpin | © *RTO Insider*

Brostrøm said the industry has matured over the last two decades as it has moved from “bespoke” projects to more standardization. At the same time, the technology has advanced from 3.6-MW turbines in 2009 to 8-MW turbines today, with next-generation models expected at 12 to 15 MW.

The panel discussion, moderated by Holland & Knight partner Mark C. Kalpin, also included Walter Cruickshank, acting director of the U.S. Bureau of Ocean Energy Management, and Curtis Fisher, executive director of the National Wildlife Federation’s Northeast Region.

Since 2009, BOEM has issued 13 offshore commercial wind energy leases, giving leaseholders the right to seek approval for development plans. The U.S. currently has only one operating offshore wind project, Deepwater Wind’s 30-MW Block Island Wind Farm in state waters off Rhode Island, which went into service last December.

“We have quite a bit to learn, still, about how things will operate — how developers will move forward with their projects,” Cruickshank said.

On Aug. 31, Interior Secretary Ryan Zinke, Cruickshank’s boss, signed an order setting a one-year target for completing environmental reviews under the National Energy Policy Act following the issuance of a Notice of Intent. “We haven’t entirely figured out how we’re going to do that yet, but we are working on trying to improve our processes,” Cruickshank said.

Fisher said his organization supports offshore wind when it is sited “in the right places” and construction minimizes impacts on aquatic life. The group is especially concerned that foundations are not drilled during the migration of endangered North Atlantic right whales because the noise can disturb the marine mammals. Fewer than 500 are believed alive.

“This is our big chance” to address climate change, Fisher said. “I fundamentally believe that this is the challenge of our generation — to actually build [renewable] projects on scale to solve problems that many people think are just too big to solve.”

October 23, 2017

ISO-NE Planning Advisory Commitee Briefs: Oct. 18, 2017

ISO-NE will revise the scope of its 2027 transmission needs assessments for Eastern Connecticut, Southwest Connecticut and New Hampshire after stakeholders raised questions about the study’s dispatch modeling, Director of Transmission Planning Brent Oberlin said Wednesday.

“It seems to be as you dial in more and more on the bus basis, the dispatches seem to be very severe in some of the cases,” Oberlin said.

During the September Planning Advisory Committee meeting, ISO-NE presented the assumptions and study methodology behind the 2027 Needs Assessment Scope of Work, a study produced biannually to provide insights into the system 10 years into the future. (See “2027 Needs Assessment Scope of Work,” ISO-NE Planning Advisory Committee Briefs: Sept. 28, 2017.)

“If you look at the difference between the 90/10 cases and the 50/50 load level cases, you can see things becoming even more severe beyond what was anticipated using this new method, so we are going back and kind of hit the pause button for a second here trying to understand exactly what’s happening, what’s causing it,” Oberlin said. “We plan to come back to the November PAC to go into more detail on the issues that we’re seeing.”

Regional System Plan Tx Projects Update

Cost estimates have changed significantly for two transmission projects since the last Regional System Plan update in June 2017: the Connecticut River Valley project in Vermont (down $9.8 million) and the Maine Power Reliability Program project (up $7 million).

Fabio Dallorto, an ISO-NE transmission planning engineer, spoke about the projects and asset conditions during an update to the PAC.

The Vermont project (No. 1614) entails rebuilding a 115-kV line from Coolidge to Ascutney to resolve thermal overload. The decreased costs reflect competitive bids throughout the project and a reduction in the amount of contingency — from 50% to 10% — included in the estimates now that the projects are better defined, Dallorto said.

The RTO reported no new projects but said 16 upgrades on the project list have been placed in service since June, including four in the greater Boston area.

Western Mass. Structure Replacement

John Case of Eversource Energy reported that 19 of 263 structures on the 1231/1242 lines in western Massachusetts need to be replaced to maintain reliability. Some of the structures are more than 90 years old, and one crossing the Deerfield River lacks shield wire, which was inexplicably not replaced following a helicopter crash that damaged the wire several years ago.

ISO-NE REV William Scherman Interregional Transmission Planning — Western Mass. transmission structure damage | *Eversource Energy*

The majority of structures on the circuits are double-circuit steel lattice towers. Replacing them reduces the potential for structural failures, Case said.

The project’s scope includes installation of 15 115-kV double-circuit and four single-circuit light-duty weathering steel structures to replace lattice towers.

Eversource estimated the project will cost $8.1 million.

Environmental Update Cites Uncertainty at Federal Level

Emphasizing the “uncertainty and the changes that are afoot at the federal policy level,” ISO-NE senior analyst Patricio Silva spent half an hour updating the PAC on all relevant environmental policy and regulatory matters affecting larger generation and linear transmission projects.

“We’re seeing significant changes with the Clean Air Act, Clean Water Act, Resource Conservation Recovery Act and the National Environmental Policy Act, [which] is actually having a dramatic impact in a variety of different regulatory forms,” Silva said during his presentation.

Silva pointed out that the Trump administration has advanced with its proposed withdrawal from EPA’s Clean Power Plan, which would affect carbon dioxide emissions from existing electric generating units. (See EPA to Announce Clean Power Plan Repeal.) The agency’s New Source Performance Standards for carbon emissions are also in limbo pending a review, and related litigation has been stayed. The agency’s pause, now reversed, in implementing new ozone standards also triggered litigation, he said.

“Lastly, more technical, but of particular interest to generators, there are changes afoot in the regulations under the Clean Air Act covering start-up, shutdown and malfunction events at generators,” Silva said. “That is a rule that’s under reconsideration and that’s also subject to litigation.”

Silva noted that his presentation only covered the Clean Air Act. “I hope you’re taking away from this that there’s a lot going on and we do not know what the outcome may be on some of these actions,” he said. “In fact, we do have in the oil and gas sector under the Clean Air Act an example of a misstep, where EPA paused and stopped to reconsider a rule only to have the litigation that was being used by the industry to stop the rule swept away.”

With the Trump administration rejecting EPA’s previous approach and the D.C. Circuit Court of Appeals essentially putting rules into effect mid-step, “there’s a risk of regulatory snap-back, where depending on where the EPA is procedurally with a reconsideration or a policy or implementation change, an affected industry sector may suddenly discover that they’re facing a fully implementable standard with a compliance deadline that has passed,” Silva said.

ISO-NE is closely watching upstream oil and gas policy because it could have a variety of implications under the Clean Air Act, especially for the operations of existing and new generators, he said.

— Michael Kuser

October 23, 2017

PJM MRC/MC Preview: Oct. 26, 2017

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 (9:10-10:00)

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

A. Manual 11: Energy & Ancillary Services. Revisions, which also include changes to the Operating Agreement (OA) and Tariff, were developed to address capping of intraday offers. The current rule offer-caps units that fail the three-pivotal-supplier test, but prohibits reapplying the cap during the unit’s day-ahead commitment or minimum run time. The changes would re-evaluate capped units when offers are updated. The changes would also apply to self-scheduled resources. (See “Debate Continues on Intraday Offers,” PJM Market Implementation Committee Briefs: Oct. 11, 2017.)

B. Manual 11: Energy & Ancillary Services. Revisions developed for the offer-verification process and offer-capping logic as part of implementation of FERC Order 831. The Independent Market Monitor, which disagrees on some parts of PJM’s proposal, will offer comments. (See “Debate Continues on Intraday Offers,” PJM Market Implementation Committee Briefs: Oct. 11, 2017.)

C. Manual 14B: Regional Transmission Planning Process. Revisions developed to add information related to contingency definitions.

D. Manual 19: Load Forecasting and Analysis. Clarifies when load drop estimates are produced and includes updates from a periodic review of the manual. (See “Cleared PRD Forces Manual Revisions,” PJM PC/TEAC Briefs: Sept. 14, 2017.)

3. Balancing Ratio (10:00-10:20)

Members will be asked to endorse Tariff revisions addressing the calculation of the balancing ratio used in determining the market seller offer cap (MSOC) for the 2018 Base Residual Auction, along with an associated problem statement and issue charge. PJM is concerned that there have been no penalty assessment intervals as needed to determine the balancing ratio. The problem statement and issue charge are meant to address the issue permanently. (See “Give me a B…,” PJM MRC/MC Briefs.)

4. Distributed Energy Resources Update (10:20-10:40)

Members will be asked to endorse a proposed Distributed Energy Resources (DER) Subcommittee charter. A proposed revision that was not considered friendly by other stakeholders is being offered as a separate version. (See “Amendment on DER Charter Sparks Debate,” PJM MRC/MC Briefs.)

5. 2017 Installed Reserve Margin Study Results (10:40-10:50)

Members will be asked to endorse the 2017 installed reserve margin (IRM) study results. (See “IRM Reductions,” PJM PC/TEAC Briefs: Sept. 14, 2017.)

6. Restoration Planning Generator Data (10:50-11:00)

Members will be asked to endorse OA revisions associated with PJM sharing of restoration planning generator data with Transmission Owners. (See “TOs to Receive Confidential Generation Data for System Restoration,” PJM Operating Committee Briefs: Sept. 12, 2017.)

Members Committee

Consent Agenda (2:20-2:25)

Members will be asked to endorse:

B. Tariff and OA revisions to clarify definitions, as recommended by the Governing Document Enhancement & Clarification Subcommittee.

1. RPM Market Seller Offer Cap (1:25-1:45)

Members will be asked to endorse proposed provisions for calculation of the balancing ratio used in determination of the MSOC for the 2018 BRA. (See MRC agenda item 3 above.)

2. Intraday Offer Capping (1:45-2:00)

Members will be asked to endorse OA and Tariff revisions associated with capping of intraday offers. (See MRC item 2A above.)

3. 2017 Installed Reserve Margin Study Results (2:00-2:15)

Members will be asked to endorse the 2017 IRM study results. (See MRC item 5 above.)

— Rory D. Sweeney

October 23, 2017

New York PSC Adopts DER Rules, Sanctions ESCOs

By Michael Kuser

The New York Public Service Commission on Thursday enacted consumer protection standards for distributed energy resource suppliers.

The PSC’s order also created a manual of uniform business practices, the first rule of which stipulates that “a DER supplier shall obtain a customer’s consent to a sales agreement prior to billing a customer or enrolling a customer” in any program.

NYPSC DER distributed energy resources ESCO ESCOs — Kelly | *NY DPS*

At the commission’s monthly meeting in Albany on Thursday, Ted Kelly, assistant counsel for the state’s Department of Public Safety, testified that “as DERs become an increasingly common and significant part of electric and gas service to customers, [the commission] has both the authority and the responsibility to ensure that customers participating in DER markets and programs understand the costs and benefits of their investments and are protected from confusion, fraud and abusive marketing.” (See Comprehensive DER Oversight Best, NYDPS Hears.)

DERs take a broad range of forms, Kelly said, “from rooftop solar panels to smart thermostats, to energy-efficient and demand-responsive industrial equipment, to bio-digesters making energy from farm waste, to community-scale distributed generation projects.”

The order requires residential customers be able to cancel a contract within three business days after its receipt without charge or penalty, and that the contract include essential information about pricing, cancellation rules, tax incentives, and details of the product or service provided.

PSC Chair John Rhodes said the order “provides a thoughtful and protective balance for New Yorkers and the timing is right. We are facing important and welcome growth in these resources, and we need to be in a position to provide protection for customers against untoward practices while pragmatically not burdening developers. I also find the initial focus on [community distributed generation] and mass market [distributed generation] makes all the sense in the world.”

Penalties for a violation of the rules can range from a warning up to a ban from participation in any programs or markets authorized by the commission.

Reining in ESCOs

The PSC also said Brooklyn-based energy service company (ESCO) MPower Energy could be barred from operating in New York following more than 100 customer allegations of deceptive sales and marketing practices.

After investigating complaints dating back to 2015, the commission said MPower must justify within 30 days why it should be allowed to continue operating in the state. The PSC also gave the firm seven days to show why it should be permitted to serve low-income customers, whom the commission said are frequently the victims of aggressive and misleading sales practices by ESCOs. (See NYPSC Limits ESCO Service, Sets New DER Compensation.)

The commission also determined that three ESCOs — Just Energy NY, National Fuel Resources and Zone One Energy — can continue serving low-income customers, while it denied waiver requests for four others: Agway Energy Services, Stream Energy, South Bay Energy and New Wave Energy.

The PSC in December 2016 banned most ESCOs from serving low-income customers but said it would consider waivers for any company that promised to offer bill savings or that could guarantee benefits to those customers. A state court earlier this year issued a temporary restraining order on the ESCO ban, which has been since lifted. (See Court Blocks NYPSC Order Barring ESCO Contracts.)

‘Yes’ to Community Choice Aggregation

The PSC approved the nonprofit Municipal Electric and Gas Alliance (MEGA) to implement a community choice aggregation (CCA) program for several Upstate New York municipalities.

Under the order, additional municipalities will be allowed to form such programs in the future, which “enable communities to take greater control of their energy choices through a transparent and competitive process driven by the consumers themselves,” Rhodes said.

Commissioner Diane Burman asked whether CCAs were subject to the just-issued rules for DER. Kelly said they would be if they included a DER component.

Utilities Prepped for Winter

The state’s major energy utilities expect to have adequate fuel supplies on hand for the coming winter, the commission heard.

“Each utility has a unique mix of assets to serve a unique mix of customers,” said Cynthia McCarran, PSC deputy director for natural gas and water. In her winter preparedness report, McCarran highlighted the efforts by some utilities, notably Consolidated Edison and New York State Electric and Gas, to focus on using demand response programs and so-called “non-pipes alternatives” to meet growing space and water heating needs.

“We anticipate energy consumers will benefit from adequate capacity and supply if we see a harsher-than-expected season,” Rhodes said.

The report said that natural gas bills in general are projected to be slightly higher this winter than historical averages and compared to last winter, which was warmer than normal. On the electric side, this winter’s commodity prices statewide are projected to be slightly higher than last winter, but significantly lower than the historical average.

Commission staff reported that major dual-fuel generation owners are continuing to follow the lessons learned from the harsh 2013-14 winter, including topping off fuel oil storage tanks ahead of the season, making firm arrangements for fuel oil replenishment, and ensuring that plant equipment has been prepared for winter operations.

“The electric utilities have continued to perform well in reducing the electric supply price volatility of their full service residential customers,” McCarran said. “The utilities have hedged approximately 70% of their estimated statewide full service residential energy needs to protect against unexpected electric market price swings that could occur this winter.”

October 23, 2017

FERC Sees Discrepancies in MISO GIA Rules

By Amanda Durish Cook

FERC last week opened a Section 206 investigation into inconsistencies in MISO’s Tariff after re-examining the 2016 termination of a North Dakota wind farm’s generator interconnection agreement (GIA).

MISO FERC GIAs Section 206 — | *EDF Renewables*

The commission on Thursday said MISO’s rules may not be just and reasonable because of discrepancies between the generator interconnection procedures outlined in the RTO’s Tariff and its pro forma GIA. It required MISO and interested parties to file briefs for a paper hearing (EL17-18). FERC expects to render a final decision in June and issued an Oct. 19 refund date.

The commission’s concern centers on a pre-2012 provision in the generator interconnection procedures that allowed an interconnection customer to extend its commercial operation date by up to three years without losing its position in the interconnection queue if MISO found that the extension would not adversely impact lower-queued customers. The provision was narrowed in 2012 so that once entering the definitive planning phase, MISO only allowed the three-year extension if it was caused by a change in milestones by another party to the GIA or a change in a higher-queued interconnection request.

MISO added a third provision for study delays in 2016. At the time, FERC said, “MISO’s proposal to limit the types of changes permissible in the definitive planning phase is consistent with the need to ensure that a project that enters the definitive planning phase is ‘definitive.’”

However, MISO’s GIA was never edited to add the three conditions for a three-year extension and “effectively provides interconnection customers an ability to extend their [commercial operation date] by three years before MISO can seek to terminate a GIA,” according to the commission.

FERC pointed out that MISO has cited the three-year limit in its generator interconnection procedures when terminating GIAs and said the RTO’s latitude to terminate GIAs is “permissive in nature.” The commission also said MISO’s outright termination of GIAs based on the three-year condition ignores its material modification analysis process, which is triggered when an interconnection project experiences changes that affect cost or in-service timing.

FERC said MISO’s interconnection procedures should be revised to reference its GIA and “allow that once a GIA is executed or filed unexecuted, a three-year period from the [commercial operation date] should lapse before MISO seeks to terminate the GIA.”

The issue was initially raised by EDF Renewables subsidiary and wind developer Merricourt Power Partners, which contested FERC’s acceptance of a MISO notice of termination of a GIA entered into by enXco Development and subsequently assigned to Merricourt. (See FERC Upholds MISO Cancellation of GIA.) At that point, the 75-turbine, 150-MW Merricourt wind project in North Dakota had missed its Dec. 1, 2012, commercial operation date by more than three years.

In seeking rehearing of the decision, Merricourt had argued that the commission erred by relying on MISO’s generator interconnection procedures alone and not considering language in the GIA.

FERC ultimately denied Merricourt’s request for rehearing of the termination, saying that MISO’s generator interconnection procedures don’t allow the three-year-plus commercial operation date extension the company sought, even considering “factors beyond the plain language” (ER16-471-001). The commission also said that it could not consider MISO’s study delay provision for Merricourt because it wasn’t yet active at the time the company missed its operating date.

FERC Commissioner Cheryl LaFleur issued a concurring statement, saying the investigation would provide “needed clarity to MISO and interconnection customers regarding their respective obligations going forward.” LaFleur was the sole dissent in FERC’s first decision to cancel the GIA, saying it could create barriers for other wind projects.

“I concur in the decision to deny Merricourt’s requested relief at this time. While I would have granted that relief in March 2016, it is now over a year and a half later, past even the Sept. 30, 2017, [commercial operation date] extension date sought by Merricourt. I do not see a basis to grant rehearing at this point,” LaFleur said.

EDF is still working to secure permitting from the North Dakota Public Service Commission for the project.

October 23, 2017

$23 Million Owed to Ratepayers in Presque Isle SSR Case

By Amanda Durish Cook

FERC ruled Thursday that Wisconsin Electric Power Co. overcharged ratepayers on Michigan’s Upper Peninsula by almost $23 million under MISO-ordered system support resource agreements.

The commission largely agreed with an administrative law judge’s initial decision on refunds under two SSR agreements that kept the 344-MW Presque Isle coal plant in Marquette, Mich., running in 2014 and early 2015 for reliability (ER14-1242-006, et al.).

FERC SSR Presque Isle Michigan Lower Peninsula — Presque Isle power plant | *WEPCo*

Judge Michael Haubner issued an initial decision in July, saying WEPCo had overcharged ratepayers over the SSR agreements. (See Upper Peninsula Ratepayers to Seek FERC Probe of Billing Fraud.)

WEPCo had argued that the commission should accept its simple three-year average of historical costs from 2011 to 2013 as basis for compensation in the SSR agreements, but FERC took the judge’s view, agreeing that SSR compensation should be limited to actual costs. FERC said the plant’s compensation “must be limited to Wisconsin Electric’s going-forward costs, and the record shows that the negotiated amount was not shown to be a reasonable estimate of Wisconsin Electric’s going-forward costs. In fact, the negotiated amount greatly exceeded Wisconsin Electric’s actual going-forward costs.” The commission also rejected the company’s portrayal of the order as “retroactively implementing a new standard for SSR compensation without providing fair notice.”

Under MISO’s first SSR agreement (Feb. 1 through Oct. 14, 2014), WEPCo collected almost $37 million in fixed-cost compensation, but FERC said the utility should have only gotten about $23 million, resulting in a refund of about $14 million.

FERC said ratepayers were due an $8.6 million refund from MISO’s second SSR agreement (Oct. 15, 2014, through Jan. 31, 2015) because the agreement contained an excessive cost of capital and ineligible capital expenditures. FERC agreed with Haubner’s view that MISO didn’t adequately support its proposed 11.5% long-term cost of capital during the second SSR, saying 9.68% was more appropriate.

The refunds include a $2.4 million charge collected under the first SSR agreement to overhaul a generator turbine. FERC ruled the charge must be refunded to avoid WEPCo taking advantage of upgrade costs and then planning a return to service.

FERC gave MISO 45 days to make a refund report, brushing aside the RTO’s complaints that Haubner’s initial order did not provide clear guidance on how to calculate refunds.

The commission also agreed with the judge that WEPCo must refund a $1.4 million consulting services invoice relating to upgrades to bring the 61-year-old coal plant into compliance with EPA’s Mercury and Air Toxics Standards. But it stopped short of determining whether changed dates on the invoices constituted fraud.

Last year, Cloverland Electric Cooperative accused WEPCo of backdating the consulting contract after the plant operator learned that the second version of its SSR agreement would cover costs incurred from MATS upgrades under a revised fixed-cost component. MATS upgrades were ineligible for recovery under the previous SSR agreement.

“We make no findings at this time regarding whether Wisconsin Electric committed fraud or engaged in manipulation when a date was changed on an invoice for MATS compliance related costs, but we have referred the matter to the commission’s Office of Enforcement for further examination and inquiry as may be appropriate,” FERC said.

October 23, 2017

ERCOT OKs Plant Retirement; TAC Meeting Canceled

ERCOT’s Technical Advisory Committee has canceled its Oct. 26 meeting because of a limited number of items for consideration. The TAC will instead hold a one-hour web information session Monday to prepare for an email vote on the load distribution factor (LDF) library.

Staff will discuss the methodology behind generating and maintaining LDFs used in the congestion revenue rights (CRRs) and day-ahead market clearing activities. LDFs are developed using historical state estimator or supervisory control and data acquisition (SCADA).

ERCOT protocols require the ISO to maintain the appropriate LDF libraries for use in the day-ahead and CRR auctions. Staff updates the libraries by maintaining the existing LDF sets and generating new LDF sets when required, based on significant changes in systemwide load patterns.

TAC Vice Chair Bob Helton has yet to set a date for the email vote.

ERCOT Approves Barney Davis Gas Unit’s Retirement

ERCOT on Thursday approved the retirement of a 330-MW gas unit at the Barney Davis plant near Corpus Christi, saying it is not needed to support system reliability and can now be decommissioned.

ERCOT TAC technical advisory committee — Barney Davis Power Plant | *Terry Ross/Flikr*

Talen Energy announced on Sept. 27 its intention to retire the unit, triggering ERCOT’s reliability review. The unit went into service in 1974.

—Tom Kleckner

October 23, 2017

FERC Again Rejects SPP Rules on ARRs, LTCRs

By Rich Heidorn Jr.

FERC on Thursday again ordered SPP to rewrite its rules on auction revenue rights (ARRs) and long-term congestion rights (LTCRs), saying the RTO’s proposed grandfathering provisions would “inappropriately extend practices that the commission finds unjust and unreasonable” (ER17-1575).

SPP FERC ARRs auction revenue rights — Inside SPP’s control room | *SPP*

In a related order, the commission also rejected SPP’s proposal to provide ARRs and LTCRs to network service customers subject to redispatch on the same basis it provides them to customers not subject to redispatch (EL16-110). The commission ordered SPP to revise its Tariff to apply to network service customers subject to redispatch the same limitation on ARR and LTCR eligibility that the RTO currently applies to point-to-point service customers subject to redispatch.

SPP had drafted the Tariff language after the commission ordered a Section 206 inquiry in September 2016 in response to complaints by Southern Co., the American Wind Energy Association and the Wind Coalition. (See SPP Hopes Congestion Rights Rule Change Wins FERC OK.)

In Thursday’s orders, FERC approved SPP’s proposal to grandfather ARRs and LTCRs that have already been granted to network customers with service subject to redispatch. But the commission said it was not reasonable to extend the grandfathering provisions through July 15, 2017, as SPP had proposed as a transition to new ARR/LTCR eligibility rules.

SPP said it wanted to ensure that customers that contracted for network service subject to redispatch — service that is “confirmed” but has not commenced — remain eligible for ARRs for the full term of their service agreement.

The commission said that proposed revisions to section 34.6 of SPP’s Tariff were unjust and unreasonable because they would allow the RTO to provide ARRs and LTCRs to network service customers subject to redispatch while necessary transmission upgrades are constructed on the same basis it provides ARRs and LTCRs to firm transmission customers not subject to redispatch.

FERC said SPP must not allocate ARRs to customers with network service subject to redispatch on the same basis as firm transmission customers not subject to redispatch, “except for those times and amounts not subject to redispatch.” LTCRs also are barred for network customers subject to redispatch.

But the commission approved grandfathering ARRs and LTCRs already granted for network service subject to redispatch under the current language of section 34.6. “Allowing customers with network service subject to redispatch to retain their already-granted ARRs for the periods of time and the amounts of service subject to redispatch obligation and to retain their already-granted LTCRs, while preventing the future allocation of ARRs and LTCRs to such service on the same basis as firm transmission customers not subject to redispatch, appropriately balances the interests of network customers with service subject to redispatch who were granted ARRs and LTCRs based on SPP’s interpretation of its Tariff with the need to prevent ARRs and LTCRs from continuing to be awarded in an unjust and unreasonable and unduly discriminatory or preferential manner,” the commission said.

In related orders, FERC also:

Clarified that its Sept. 23, 2016, order did not prevent customers from seeking relief or address any retroactive relief (ER16-1286-002, EL16-110-001);
Rejected Southern Co. unit Alabama Power’s allegation that SPP violated its Tariff by treating customers with network service subject to redispatch as eligible to receive ARRs and LTCRs (EL17-11); and
Rejected a complaint by Buffalo Dunes Wind Project asking the commission to order SPP not to allocate new ARRs or LTCRs to network service customers subject to redispatch for the 2017-2018 allocation year (EL17-69).