Page 1444 – RTO Insider

May 13, 2016

Con Ed-PSEG ‘Wheel’ Ending Next Spring

By William Opalka

Consolidated Edison will stop using the “PSEG wheel” next April, following through on a promise it made late last year in a dispute with PJM over transmission upgrade costs.

The company said it would not renew two point-to-point transmission agreements under which Public Service Electric and Gas takes 1,000 MW from Con Ed at the New York border and delivers it through New Jersey to Con Ed load in New York City.

Con Ed, which said it has identified less costly alternatives, informed the New York Public Service Commission of its decision in a letter May 2 (12-E-0503).

The company says that renewing the wheel after its April 30 expiration would expose it to $680 million in cost allocation charges for two transmission projects that it says primarily benefit New Jersey customers.

“Con Edison no longer requires power sources from the PJM wheel for reliability purposes, and unfair cost allocations have become too costly for our customers,” spokesman Bob McGee said. “Other electric projects added in recent years that already serve our customers will help us maintain reliability. We will continue to have access to the PJM wheel in an emergency.”

PJM assigned Con Ed $629 million of the costs of PSE&G’s $1.2 billion Bergen-Linden Corridor upgrade to address a short-circuit problem. PSE&G was allocated $52 million of the cost. Con Ed was also assigned $51 million of PSE&G’s $100 million Sewaren storm-hardening project.

Con Ed contended it should pay only $29 million for the two New Jersey projects, but FERC approved PJM’s cost allocation on the Bergen-Linden project last month in a 3-1 vote. (See FERC Upholds Cost Allocation for Artificial Island, Bergen-Linden Projects.)

Paul McGlynn, PJM general manager of system planning, told the PJM Planning Committee on Thursday of Con Ed’s intentions.

“We will need to make changes to the procedures we use in planning and operations,” he said. “This is just a heads-up that we’re going to need to be discussing it in the future. As plans take shape, we will be doing analysis on them. The goal is to discuss and determine how we will manage that interface without the wheel.

“When that wheeling agreement is canceled, we will need to redo cost allocations for any and all of the projects that Con Ed has allocation for, and we’ll have to file them at FERC. They would become effective when the agreement actually terminates in the spring of 2017,” McGlynn added.

“NYISO is working with PJM to develop an effective going-forward approach for the border,” ISO spokesman David Flanagan said. “In addition, NYISO will include this change in the full range of system information currently being gathered for the 2016 Reliability Needs Assessment that will study potential reliability needs for the period of 2017-2026.”

Bergen-Linden Corridor Upgrade Source: PSEG — Bergen-Linden Corridor Upgrade *Source: PSEG*

Identification of the transmission projects that allowed Con Ed to cancel the wheel began in 2012, although for an entirely different reason. New York regulators at that time began discussions about transmission alternatives that would be needed if the Indian Point nuclear plant closed because its licenses were not renewed.

The NYPSC approved several projects in 2013 for that contingency, including three named the Transmission Owner Transmission Solutions. FERC in March accepted a cost allocation formula submitted by state regulators and New York transmission owners, including Con Ed. (See FERC OKs Settlement for NY TOTS Projects.)

One of the alternative projects, the $274.3 million “Staten Island Unbottling” would make 440 MW of generation available to the New York grid through Con Ed’s substations in a two-phase project.

However, in a February order, the NYPSC accepted a Con Ed motion to cancel the second phase. Con Ed said that once the wheel expired, transmission limitations caused by it would be eliminated and that only the $51.3 million first phase was necessary.

Suzanne Herel contributed to this article.

May 13, 2016

EPA: Methane Rules to Have Minimal Impact on Gas Costs

By Rory Sweeney

EPA said rules it issued Thursday to reduce methane emissions from oil and gas development will raise wholesale natural gas prices by less than 1%, but the industry’s leading trade group warned the “unreasonable and overly burdensome” regulations could depress shale gas development.

Infrared image of emissions from natural gas storage tank Source: Texas Commission on Environmental Quality, epa — Infrared image of emissions from natural gas storage tank *Source: Texas Commission on Environmental Quality*

The agency said the rules will cost a net $320 million annually through 2020, with a $390 million total cost reduced by $70 million in revenue from sales of methane now lost into the atmosphere. By 2025, the estimated total cost increases to $640 million, offset by gas sales of $110 million, for a net cost of $530 million. The estimates, in 2012 dollars, assume a price of $4/Mcf.

EPA estimated that the rules will reduce gas well drilling by about 0.% and production by about 0.03% between 2020 and 2025, compared to the baseline. The agency estimated wellhead prices for onshore lower-48 production will increase during that period by about 0.2% and net imports will rise by about 0.11%.

Reduced Innovation?

The American Petroleum Institute said the costs will be more than twice EPA’s estimate, pegging them at $806 million per year in 2025.

“It doesn’t make sense that the administration would add unreasonable and overly burdensome regulations when the industry is already leading the way in reducing emissions,” Kyle Isakower, API’s vice president of regulatory and economic policy, said in a statement. “Imposing a one-size-fits-all scheme on the industry could actually stifle innovation and discourage investments in new technologies that could serve to further reduce emissions.”

The new rules are designed to reduce fugitive methane emissions from compressor stations, gas processing plants and well sites, including fracking operations. The rules also cover pneumatic pumps and controllers, centrifugal compressors and reciprocating compressors. Well site compressors are exempt.

Monitoring

The rules — which cover new and modified operations — are stringent, requiring substantially greater monitoring and emissions control than before across all areas of the extraction and production process. Well sites will be required to conduct biannual monitoring using either an infrared camera or a vapor “sniffer” and must repair leaks within 30 days. Compressor stations must be quarterly. Natural gas processing plants are already checked this way for other emissions, but they now must include methane.

Gas Separator Source: EPA, natural gas, methane — Gas Separator *Source: EPA*

After fracking a well, operators will need to install equipment that separates gas from the fluid that flows back to the surface and collect or combust it. Wildcat, exploratory and low-pressure wells are required to have combustion devices but not the separation equipment.

Many of these operations were already regulated for volatile organic compounds (VOCs) and hazardous air pollutants (HAPs) — but not methane — under the 2012 New Source Performance Standards, which regulate pollutant emissions from new or modified sources. The new rules also include several edits to the NSPS, including how flares can be done, leak detection and repair, and monitoring and testing of storage-vessel control devices.

EPA said the rules are justified because the costs will be outweighed by “monetized climate benefits” of $360 million in 2020 and $690 million in 2025. Such benefits were calculated in relation to greehouse gas emissions only, but the agency said there will be additional benefits from the associated reductions in VOCs and HAPs.

Methane is second only to carbon dioxide in its overall contribution to global warming. A ton of methane traps 25 times as much heat in the atmosphere as the same amount of CO₂ over a 100-year period.

The changes to the NSPS were released along with two other rules affecting the industry. One requires emissions reductions for operations on certain Native American lands. The other clarifies what equipment should be grouped together to calculate whether a site is a major or minor emissions source.

EPA estimates about 270 full-time equivalent workers will be needed to meet compliance. The agency estimates that will increase to about 1,800 in 2025.

May 12, 2016

UPDATED: PUCO Grants FirstEnergy Rehearing on PPA; Opponents File Protests

By Ted Caddell

The Public Utilities Commission of Ohio agreed Wednesday to hear FirstEnergy’s arguments for why it should be able to withdraw its controversial power purchase agreement and substitute a new plan.

It also granted all of the applications for rehearing sought by opponents of the PPA, including the Electric Power Supply Association, the Ohio Consumers’ Counsel, the Environmental Defense Fund, the Sierra Club, the Retail Energy Supply Association and the PJM Power Providers Group.

“Because of the number and complexity of the assignments of error raised in the applications for rehearing, as well as the potential for further evidentiary hearings in this matter, we find that it is appropriate to grant rehearing at this time,” the commission said (14-1297-EL-SSO). “This will allow parties to begin discovery in anticipation of potential further hearings.”

Although its rehearing request also was granted, the EDF protested the ruling.

“So, without listening to the arguments against the deal, the PUCO rubberstamped [FirstEnergy’s] request for a rehearing,” the EDF’s Dick Munson wrote in a blog post that went up within minutes of PUCO’s order.

Both FirstEnergy and American Electric Power were granted eight-year PPAs after more than a year of legal wrangling. But their victories were short lived, as FERC ruled that the agreements would require a review that could nullify them.

Opponents Sound Off

On Thursday, PUCO received a stream of filings against the modified FirstEnergy plan, including those from the Ohio Energy Group, the Northeast Ohio Public Energy Council, the Sierra Club, the PJM Power Providers Group (P3) and the Electric Power Supply Association.

P3 and EPSA accused FirstEnergy of doing an end-around play to avoid review by FERC. FirstEnergy, they said, is wrongly “attempting to use the commission’s application for rehearing process to circumvent the FERC order.”

“FirstEnergy, however, has made a mistake in how it presented its new PPA proposal to this commission,” they wrote. “FirstEnergy did not include or mention its new proposal in its application for rehearing, robbing the commission of jurisdiction over the proposal in this proceeding. This means that the commission cannot grant rehearing on the proposal and, contrary to its May 11, 2016, action, cannot reopen this proceeding to allow discovery on the proposal. The proposal is dead on arrival and the commission must follow the law by not exercising jurisdiction through rehearing.”

The Sierra Club also filed in opposition to the FirstEnergy plan.

“While FirstEnergy is trying to put old wine in a new bottle to escape review under federal customer protection standards, its latest shareholder bailout proposal is the same bad deal for Ohio customers,” said Shannon Fisk, managing attorney at Earthjustice, which represents the Sierra Club. “FERC smartly put a hold on FirstEnergy’s bailout so that customers would not be losing money while the legality of the bailout is fully reviewed. PUCO should not sign off on FirstEnergy’s brazen effort to evade FERC’s order.”

Thursday was also the deadline for arguments against AEP Ohio’s request to modify its PPA, and that docket also swelled with filings from opponents.

FERC ruled April 27 that the PPAs — in which AEP’s and FirstEnergy’s regulated utilities would purchase output from the companies’ merchant generators — must be reviewed under the Edgar affiliate abuse test (EL16-33 and EL16-34).

AEP CEO Nick Akins said after FERC’s ruling that the company would either lobby Ohio lawmakers to reregulate the state’s electricity market or sell off its Ohio fleet rather than submit to FERC review. FirstEnergy CEO Chuck Jones has also said he would welcome reregulation. (See All Eyes on AEP, FirstEnergy with Ohio PPAs in Doubt.)

Both utilities then filed for rehearing with PUCO. FirstEnergy asked the commission to withdraw its PPA and replace it with a customer charge that would still protect its aging power plants. Munson called FirstEnergy’s new plan “sleight of hand” and said PUCO’s decision Wednesday “suggests commissioners care more about appeasing a politically connected company than protecting customers or considering both sides of an argument.”

AEP Request

AEP scaled back its original request for PPAs for all of its 3,100-MW Ohio merchant fleet, asking PUCO for an agreement covering only its 440-MW share of the Ohio Valley Electric Corp. (14-1693-EL-RDR, 14-1694-EL-AAM). AEP said it will stand by its commitment to develop 900 MW of renewable energy — a promise that convinced the Sierra Club to sign on to its plan — with certain provisos.

On Thursday, the Office of the Ohio Consumers’ Counsel and the Appalachian Peace & Justice Network jointly filed a memorandum urging PUCO to deny AEP’s request to change its “electric security plan” (ESP).

“Even though AEP Ohio appears to have shuttled its plans for an affiliate PPA, in light of FERC’s rulings, it nonetheless has come up with another way to extract money from customers,” the two organizations wrote. They said AEP Ohio’s idea to seek a PPA covering only the OVEC portion of its generating fleet was already denied once by PUCO in a 2015 decision. “There is no reason to stray from that decision,” they wrote. PUCO at that time, they said, ruled that a OVEC-only PPA rider “would not provide a sufficiently beneficial financial hedge, or other commensurate benefits, to AEP Ohio’s customers to justify approval.”

“The PUCO should also consider that when AEP Ohio negotiated the OVEC contract, it agreed to an allocation of risk regarding Capacity Performance penalties and bonuses,” the groups argued. “The PUCO should not undo the deal that AEP Ohio itself struck by bailing it out from the agreed-to risk allocation and imposing the risk on customers.”

The groups also argue that PUCO’s rules don’t allow AEP Ohio to modify the ESP. It only allows it to accept PUCO’s modifications or withdraw and terminate its entire request, they said.

P3 and the Electric Power Supply Association also argued that AEP’s rehearing request and “rehashed proposal” should be denied, also noting PUCO’s 2015 ruling.

“With the affiliate PPA removed from the PPA rider, AEP Ohio is left with only its OVEC entitlement — a construct this commission expressly rejected in 2015,” they wrote. “The commission should deny AEP Ohio’s application for rehearing, reverse its approval of the stipulation and terminate this hearing.”

The Mid-Atlantic Renewable Energy Coalition filed a memo supporting AEP’s rehearing request, saying it is necessary to “preserve the significant public policy benefits” of the original renewable energy agreements.

May 12, 2016

FERC Rejects Challenges to PJM Capacity Performance

By Rich Heidorn Jr.

FERC late Tuesday rejected multiple rehearing requests on PJM’s Capacity Performance rules, but ordered the RTO to revise Tariff language regarding auction revenue rights and clarify language on several other issues, including risk premiums and “nonphysical” constraints.

The ruling, on the eve of PJM’s Base Residual Auction Wednesday, granted only one rehearing request, ordering the RTO to change its force majeure rules regarding load-serving entities’ ARRs (ER15-623, EL15-29, EL15-41).

The commission rescinded its approval of Tariff language allowing the RTO to deny financial transmission rights awards for an “unanticipated event outside the control of PJM.” The commission had agreed that PJM should have some discretion in determining when to relax a binding constraint in allocating FTRs. (FTRs can be purchased or converted from ARRs, which are allocated to network and firm point-to-point customers.)

American Municipal Power, Old Dominion Electric Cooperative and Southern Maryland Electric Cooperative complained that the change could affect LSEs’ shares of stage 1A ARRs and thus their abilities to hedge transmission costs.

The complainants said the language was different from PJM’s other force majeure changes because it applied to PJM’s obligations to LSEs rather than market participants’ performance obligations.

They argued the revised Tariff lacked any limits on PJM’s exercise of its discretion. In most cases, they added, FTR allocations will have already been made or be underway before PJM makes its decisions, leaving them facing “the prospect of an unlikely post-settlement remedy.”

FERC agreed.

“Upon further consideration, we agree that PJM has not adequately explained why its existing rules are unjust and unreasonable regarding its duties to load-serving entities as they relate to the allocation of ARRs and FTRs,” it said, ordering the RTO to reinstate “its prior just and reasonable” Tariff language.

Nonperformance Charges

The commission also required several revisions to PJM’s July 29, 2015, compliance filing in response to FERC’s June 9 order conditionally approving Capacity Performance. (See FERC OKs PJM Capacity Performance: What You Need to Know.)

One required change concerns whether a capacity resource will be subject to nonperformance charges if PJM does not schedule it solely because of operating parameter limitations in the resource’s offer.

FERC said a literal reading of the Tariff suggests that a provision exempting resources from the nonperformance charge if the resource is not scheduled through PJM’s security-constrained economic dispatch takes precedence — meaning a resource’s undelivered megawatts would not be counted as a performance shortfall even if it would otherwise be needed.

“This outcome is inconsistent with the commission’s finding in the Capacity Performance order,” it said.

It directed PJM to revise the Tariff “to make clear that, notwithstanding PJM’s determination that a scheduling action was appropriate to the security-constrained economic dispatch of the PJM region, any undelivered megawatts will be counted as a performance shortfall if such megawatts otherwise would be needed but for an operating parameter limitation specified in the market seller’s energy offer.”

Fixed Resource Requirement Phase-in

The commission also found fault with PJM’s proposal to apply the Capacity Performance rules to all fixed resource requirement (FRR) entities beginning with the 2019-20 delivery year.

FERC said the proposal to apply Capacity Performance rules to FRR entities with no ongoing five-year election commitment beginning with delivery year 2020/21 was “reasonable in concept.”

But it said its intent was that the rules would not apply to an entity that was within its initial five-year FRR commitment period when the CP order was issued, meaning an entity that first elected to use the FRR option for delivery year 2015/16 would not become subject to the rules until delivery year 2020/21.

“PJM’s proposed compliance to apply the Capacity Performance requirements to all fixed resource requirement entities beginning with the 2019/20 delivery year is therefore not consistent with the commission’s intent,” it said.

Quantifiable Risk

NRG Energy, Dynegy, Public Service Enterprise Group, the PJM Power Providers Group and the Independent Market Monitor won their requests for clarification of Tariff language regarding “quantifiable risks” of becoming a capacity resource.

The commission said it disagreed with complaints that PJM’s language narrowed sellers’ ability to include quantifiable, reasonably supported risks in their offers.

But it required the RTO to clarify that the method it described for justifying such risks was not all-inclusive “and that a capacity market seller may use other methods or forms of support for a risk premium to meet the ‘reasonably supported’ threshold.”

“The risk that market sellers face from becoming capacity resources under the new capacity market construct requires a complex calculation that depends on the company-specific nature of valuing performance risk,” the commission said.

PJM had said a risk would be considered reasonably supported “if it is based on actuarial practices generally used by the industry to model or value risk and … used by the capacity market seller to model or value risk in other aspects of the capacity market seller’s business.”

Nonphysical Constraints

FERC also said PJM went too far in requiring that gas generators seeking to qualify for consideration of “legitimate, constraints unrelated to the characteristics of the unit” — which PJM calls nonphysical constraints — must obtain the most flexible gas pipeline transportation contract.

The commission said PJM’s filing went beyond the scope of its compliance directive requiring the RTO to allow parameter limitations for operational constraints.

“PJM’s proposal also is unclear since operational constraints imposed by a gas pipeline may have little relationship to the underlying flexibility of a transportation contract, but are related to pipeline operational characteristics, and cannot be eliminated by contract term or service choice,” the commission said.

“Furthermore, we find that provision unduly discriminatory as it establishes a prerequisite applicable only to gas generators. We also agree with protesters that the language is vague and would require PJM to exercise significant discretion in determining whether a generator has obtained the most flexible contract available.”

It ordered the RTO to remove the offending language from its Operating Agreement and Tariff and to “make explicit that the revisions here do not preclude resources other than natural gas generators from establishing legitimate, nonphysical constraints.”

Bay Again Dissents

Chairman Norman Bay, who voted against the original Capacity Performance order, also opposed the latest ruling, issuing an 11-page dissent reiterating his position that the construct’s “multi-billion-dollar cost to consumers exceeds the benefits.”

“Furthermore, and equally important, the market design itself is flawed. Compensation for capacity resources is so generous, and the penalties for nonperformance are so weak, that resources can profit even if they are unable to perform when they are most needed, thereby undercutting the very purpose of the program,” he said.

May 12, 2016

Ohio Gov. Kasich Names Asim Haque for PUCO Chair

Gov. John Kasich on Monday named Public Utilities Commission of Ohio Vice Chair Asim Haque to replace outgoing Chairman Andre Porter.

Porter announced last month that he would be leaving the commission on May 20. While Porter, who served little more than a year, hasn’t said where he would be going, industry speculation has him taking a position with MISO. The RTO has declined repeated requests to comment on the speculation.

Asim Haque, PUCO, Kasich — Asim Haque *Source: PUCO*

Haque, appointed to the commission three years ago by Kasich, will be the fourth PUCO chairman in four years. Haque will be guiding the commission through the ongoing controversy over power purchase agreements for American Electric Power and FirstEnergy.

“Throughout his three years of service on the PUCO, Commissioner Haque has demonstrated an exceptional command of the issues and challenges facing Ohio’s energy markets. No one is better prepared to apply that level of expertise and independent judgment to the role of chairman,” Kasich said.

“I am honored by the governor’s confidence in my ability to lead the commission, and I look forward to working with my fellow commissioners and the talented PUCO staff to foster energy policies that further strengthen Ohio’s job growth with affordable, reliable power,” Haque said.

Haque has bachelor’s degrees in chemistry and political science from Case Western Reserve University and a law degree from the Ohio State University Moritz College of Law.

A nominating council will now have to come up with four names to submit to Kasich for consideration to fill Haque’s old seat, a process that could take months.

— Ted Caddell

May 12, 2016

CFTC to Add ‘Private Rights’ to RTO Exemption

By Tom Kleckner

The U.S. Commodity Futures Trading Commission said Tuesday that it is amending its 2013 order exempting RTO energy transactions from certain provisions of the Commodity Exchange Act to clarify that it does not bar private rights of action.

The proposed amendment, approved in a 2-1 vote, would “explicitly” provide that the RTO-ISO order does not prevent private parties from filing lawsuits.

CFTC said the private right of action’s existence is “not inconsistent with or detrimental to cooperation between the CFTC and FERC.” Preserving that right, the commission said, “will not cause regulatory uncertainty or duplicative or inconsistent regulation.”

“Moreover, conflicting judicial interpretations regarding the nature of the covered transactions would not affect the jurisdiction of FERC or any relevant state regulatory authority.”

The amendment stems from CFTC’s April 2013 order, which exempted financial transmission rights and other electricity transactions subject to tariffs approved by FERC or the Public Utility Commission of Texas from most of the CEA’s provisions, while retaining its general anti-fraud and anti-manipulation authority.

SPP was the only grid operator not party to the order, as its day-ahead market did not become fully operational until March 2014. The RTO sought the same exemptions that the commission granted the others, but the commission’s May 2015 draft order on SPP included a preamble stating its intent to preserve private rights of action under Section 22 of the CEA.

Although the commission said it did not intend to exclude private suits in its 2013 order, the 5th Circuit Court of Appeals ruled in February that it had done so. The appellate court upheld a 2015 ruling by the U.S. District Court for the Southern District of Texas dismissing a lawsuit alleging that some generators in ERCOT were intentionally withholding electricity and manipulating prices in the derivatives commodities market (Aspire Commodities v. GDF Suez Energy N. Am., No. H-14-1111). The court said that the private right of action was “unavailable to [p]laintiffs” due to the CFTC’s exemption order.

In March, the ISO/RTO Council, the Texas PUC, the Edison Electric Institute and other witnesses asked the commission to reverse its position, saying the SPP order could undermine the broad exemptions earlier granted to the other grid operators. PJM, ERCOT and CAISO also raised objections last year.

Last month, U.S. Sen. John Boozman (R-Ark.) introduced an amendment to CFTC’s reauthorization bill that would prevent the agency from adding the private rights option to the 2013 order. (See Congress May Order CFTC to Back Down on Private Rights.)

CFTC Chairman Timothy Massad said he appreciated “the desire of businesses to have as little regulatory uncertainty as possible” but that the commission must also ensure “there is adequate recourse” for market participants.

“Private rights of action have been instrumental in helping to protect market participants and deter bad actors,” Massad said in a statement. “These actions can also augment the limited enforcement resources of the CFTC and serve the public interest by allowing harmed parties to seek damages in instances where the commission lacks the resources to do so on their behalf.”

In a lengthy dissent, Commissioner J. Christopher Giancarlo said the amendment “manages to simultaneously toss legal certainty to the wind and threaten the household budgets of low- and middle-income ratepayers by permitting private lawsuits in heavily regulated markets that are at the heart of the U.S. economy.”

The proposed amendment will be open for public comment for 30 days once it is published in the Federal Register.

May 9, 2016

Company Briefs

More than 60% of Exelon shareholders voted against the company’s 2015 executive compensation plan, a nonbinding vote that the proxy advisory firm Institutional Shareholder Services said reflected discontent with the easy terms of CEO Chris Crane’s $16 million compensation package.

“Exelon’s stock performance lagged [behind] many of its peers over the last three- to five-year periods,” ISS said in a report released before the vote. “However, nearly every component of CEO pay increased during FY2015, and incentive awards, both long and short, were earned at above-target levels and based on nearly flat or lowered performance goals.”

Exelon said it was taking the vote into advisement. “Our shareholders have spoken on executive compensation and although it was an advisory vote, we take the vote and shareholder feedback very seriously and are currently re-evaluating our executive compensation programs to address this feedback.”

More: Crain’s Chicago Business

PPL Cuts Default Price For Pa. Electric Customers

PPL Utilities said it is cutting its default price for residential customers who don’t shop for electricity from 7.878 cents/kWh to 7.393 cents, and from 7.731 cents/kWh to 6.593 cents for small commercial customers. The new prices for “default service” take effect in June.

The company sets the “price to compare” twice a year, in December and June. This supply charge is based on what it costs PPL to obtain the power, so it is a direct pass-through with no profit to the utility.

More: The Morning Call

Xcel Moves Wis. Solar Projects Ahead Despite Slow Sales

Xcel Energy will proceed with the construction of two community solar farms in La Crosse and Eau Claire counties in Wisconsin even though the company has only sold 12% of the available 2 MW.

The company’s report to the Wisconsin Public Service Commission shows four commercial customers have reserved 140 kW and 42 residential customers reserved 99 kW. Xcel, however, estimates it will sell at least 95% of the power from both projects by the end of the year, when they are expected to begin producing electricity.

“While we have not received a large number of nonresidential subscriptions yet to date, many of our nonresidential customers are in the process of running large subscription recommendations through their internal decision-making processes,” Xcel wrote in the PSC report.

More: The Chippewa Herald

DTE’s Fermi 2 Nuclear Plant Closes for Repairs

DTE Energy’s Fermi 2 nuclear power plant has been shut down to repair a component in the electrical distribution system, according to spokesman Stephen Tait.

DTE’s monitoring program, Tait said, indicated the reactor in southeastern Michigan needed the repair. Other maintenance work will take place during the shutdown.

No date was given on when the plant would resume service.

More: The Monroe News

Cracked Bolts Lead to Prolonged Salem Outage

The discovery of cracks to a number of bolts inside the core of the Salem 1 nuclear reactor on Artificial Island have delayed the unit’s coming back online, according to the Nuclear Regulatory Commission and PSEG Nuclear.

A routine inspection found cracks on 18 of the reactor’s 832 baffle bolts during a refueling outage. The company is extending the outage to conduct further inspections.

NRC spokesman Neil Sheehan said some of the bolt heads had broken off, but he and PSEG officials said there was no danger. A recent inspection at Entergy’s Indian Point nuclear station in New York found 227 of its 832 bolts needing replacement.

More: NJ.com

Eversource Energy Names New CFO

Eversource Energy last week announced that Phil Lembo will succeed Jim Judge as the company’s CFO. The announcement came the same day Judge took over as CEO for the retiring Tom May.

Lembo had been vice president and treasurer for Eversource since the 2012 merger between Northeast Utilities and NSTAR. Before that, he served as vice president and treasurer for NSTAR since 2009. He has been with the company for 33 years.

More: Eversource

More Solar Power to Go Online for Duke Energy

The sixth 5-MW solar project that Duke Energy Renewables purchased from Community Energy is set go live this month in North Carolina.

The generation is being sold to Dominion NC Power under a 15-year agreement. Duke has installed about 450 MW of solar in North Carolina.

More: power-technology.com

Exxon Partnering with Fuel Cell Co. to Capture Carbon

ExxonMobil has agreed to invest an unspecified amount into Connecticut-based FuelCell Energy to develop a process that could dramatically cut carbon dioxide emissions from power plants while improving electrical output.

The initial phase of the deal will finance one to two years of research. A second phase would test the technology in “a small-scale pilot project.”

FuelCell and ExxonMobil have been cooperating on research since 2014. The goal of the project is to eventually create large-scale systems that can capture CO₂from the steam turbines used in coal- and natural gas-powered electric generating plants and convert it to additional electricity in fuel cells.

More: Hartford Courant

May 9, 2016

FERC Upholds 3 MISO SSR Cost Allocations in Upper Peninsula

By Amanda Durish Cook

FERC last week rejected all challenges to system support resource rate schedules for three aging power plants in Michigan’s Upper Peninsula.

miso, ferc, ssr, ssr cost allocations — Presque Isle Plant *Source: We Energies*

The commission upheld MISO’s SSR cost allocation for the Presque Isle, Escanaba and White Pines power plants (ER14-2952, et al.), rejecting requests for rehearing from a dozen parties, including the Michigan Public Service Commission, the City of Mackinac Island, the Sault Ste. Marie Tribe of Chippewa Indians, Upper Peninsula Power Co., the City of Escanaba and Cloverland Electric Cooperative.

FERC also accepted MISO’s compliance filing, which detailed the calculation for load distribution factors. The RTO also eliminated a proposal to select load buses that have an 80% effect on transmission constraints as SSR unit beneficiaries.

In September, FERC generally accepted MISO’s SSR cost allocation methodology, saying it “assigns SSR costs directly to load-serving entities serving loads that would contribute to thermal or voltage reliability violations in the absence of the Presque Isle, Escanaba and White Pine SSR units.” (See FERC OKs MISO’s SSR Allocation for 3 Plants.)

The approved cost allocation took the place of an optimization-load balancing authority approach found in MISO’s Business Practices Manuals. While FERC defended the new allocation on several fronts, it ordered MISO to file a report by mid-June that details how the RTO plans to distribute refunds to LSEs overcharged under the former approach. The commission said it would address arguments over effective dates and refund obligations “upon the filing of the refund report.”

May 9, 2016

CAISO EIM Boosts Market for Renewables in Q1

By Robert Mullin

The recently expanded western Energy Imbalance Market (EIM) provided California a new outlet for its surplus renewable output last quarter, according to CAISO’s quarterly economic benefits report.

The EIM produced $18.9 million in overall financial benefits for its participants during the first quarter of 2016, up from $12.3 million the previous quarter, the report said.

CAISO attributed the increase to the participation of NV Energy, which joined the real-time market in December 2015. The utility’s addition significantly improved transfer capability between the ISO and the balancing areas belonging to PacifiCorp — the EIM’s first participant — creating a more unified footprint. (See NV Energy has Smooth EIM Integration, CAISO Says.)

Despite its key contribution to unifying the market, NV Energy realized just $1.7 million of the gross benefits during the quarter. The largest share — $10.85 million — flowed to PacifiCorp, while CAISO picked up $6.35 million.

CAISO: Exporter

Nested into the report was what could be the most significant development of the quarter: the rise of CAISO as a real-time energy exporter into other areas of the EIM. CAISO has generally been an importer of electricity since the launch of the market in November 2014. NV Energy’s entry into the market expanded transfer capacity between the ISO and PacifiCorp East from 200 MW to about 570 MW.

“A significant level of the energy that was exported by the ISO was renewable generation,” CAISO said.

That data supports arguments for an expanded EIM — and potentially a Western RTO. Advocates contend a larger market is necessary to reduce curtailments of the increasing amount of renewable generation in the West. CAISO estimates that its EIM operation helped it avoid curtailing 112,948 MWh of renewable generation during the first quarter.

“If not for energy transfers facilitated by the EIM, some renewable generation located within the ISO would have been curtailed via either economic or exceptional dispatch,” CAISO said.

The renewable output made possible by the reduced curtailments prevented the emission of more than 48,000 metric tons of CO₂for the quarter, CAISO estimates. The ISO also speculates that the cut in curtailments also reduced the number of renewable energy certificates retracted, although that benefit was not quantified in the report.

The ISO’s calculations are based on estimated cost savings from EIM dispatch compared with a “counterfactual” case of dispatch without the market. Benefits fall into three categories, including:

More efficient inter- and intraregional dispatch in the 15-minute and real-time markets;
Reduced curtailment of renewable energy; and
Reduced need for flexibility reserves in all balancing areas.

For individual EIM participants, benefits take the form of either cost savings — such as from reduced need for reserves — or increased profits from merchant operations. CAISO’s quarterly report does not break down estimates along those lines.

CAISO says the EIM has benefited participants to the tune of $64.6 million since the market’s 2014 rollout.

May 9, 2016

SPP Sees Hope for Joint Studies in NIPSCO Order

By Tom Kleckner

With prospects for a second coordinated system plan study with MISO looking bleak, SPP’s Seams Steering Committee considered last week whether it might find some relief in a recent FERC order related to the MISO-PJM seam.

FERC last month ordered MISO and PJM to make changes in their interregional transmission planning process as a result of a complaint filed by Northern Indiana Public Service Co. (EL13-88). (See FERC Orders Changes to MISO-PJM Interregional Planning.)

That led the SSC — which met via conference call Friday as MISO and PJM were holding their Interregional Planning Stakeholder Advisory Committee meeting — to wonder whether the commission’s directives in the NIPSCO docket would apply to the MISO-SPP seam as well.

“It’s hard for me to imagine the rationale for having different criteria for different seams,” SSC Chair Paul Malone said.

“If they change things on the PJM seam, I don’t see why [MISO] would be opposed to being consistent on the SPP seam,” American Electric Power’s Jim Jacoby said.

David Kelley, SPP’s director of interregional relations, noted that FERC directed MISO and PJM to make changes to their joint operating agreement’s cost allocation for interregional projects. The commission ordered that costs be allocated in proportion to the total benefits as calculated in “each RTO’s respective tariff,” rather than how benefits are calculated in the JOA.

FERC said with the change, “each RTO will then determine whether the potential interregional economic transmission project meets its individual 1.25-to-1 benefit-to-cost threshold using the RTO’s pro rata share of the total cost based on its share of the total dollar value of the benefits.”

“We have the same exact language PJM and MISO have. It’s hard for me to fathom there wouldn’t also be a directive to apply it to our seams,” Kelley said. “We don’t have a threshold test, which I believe MISO and PJM do, [but] the order asked them to get rid of it.”

Ameren’s Pat Hayes, who was also participating in the IPSAC meeting, told the SSC that MISO was planning to seek clarification from FERC on whether the NIPSCO issues were unique to the MISO-PJM interregional process or applied to all interregional processes.

SPP is not an intervenor in the docket, though some of its members, including AEP, are. “We’re more than happy to submit those questions” raised, AEP’s Kip Fox said.

Kelley said SPP is still digesting the order, but he promised to have more feedback for the committee’s June meeting.

MISO’s 345-kV threshold for interregional projects has been one of the stumbling blocks in selecting interregional projects on the MISO-SPP seam. The RTOs were unable to agree on a single project in last year’s joint study, and MISO staff is currently recommending not to pursue a second study this year. (See MISO, SPP Disagree on 2016 Joint Study.)

MISO’s Planning Advisory Committee is scheduled to take a final vote on whether to pursue the joint study during its May 18 meeting. SPP staff said stakeholders unable to participate in the March SPP-MISO IPSAC meeting had requested extra time and additional materials from MISO before making a decision.

The SSC voted last month to pursue a targeted transmission study with MISO. (See “Seams Steering Committee Seeks ‘Targeted’ MISO Seam Study,” SPP Briefs.) Staff said in the future, such votes will be held at joint IPSAC meetings to avoid delays.

SPP’s Gerardo Ugalde said MISO paid SPP more than $1 million for temporary and permanent flowgate relief in March. Since market-to-market operations began in March 2015, SPP has used the process to manage congestion on 45 SPP flowgates and 50 MISO flowgates, he said.

Ugalde shared staff’s analysis of flowgates where real-time congestion was observed for more than 10 days. SPP compared internal flows against firm-flow entitlements. But because the six-flowgate sample size was so small, staff is currently running studies to determine how day-ahead clearing would change if SPP started using FFE limits.