Page 1167 – RTO Insider

June 5, 2018

MISO Mulls Additional Emergency Communication

By Amanda Durish Cook

MISO is asking stakeholders if they would like the RTO to provide generators an additional emergency notification declaring a maximum generation alert.

maximum generation alert MISO — Van Schaack | © *RTO Insider*

Manager of Unit Commitment and Dispatch Phil Van Schaack said MISO is considering creating a new capacity advisory or expanding its maximum generation criteria to include more conditions in order to provide market participants more advanced notice of possible emergency declarations for unit operators.

MISO was prompted to consider the move after forecasting possible emergency conditions for May 14 (a Monday) on May 11 (a Friday). The RTO ultimately declared an emergency alert just ahead of the weekend.

“Load, weather, very warm temperatures, outages made things very tight on May 14,” Van Schaack said at a May 31 Reliability Subcommittee meeting.

However, MISO terminated the maximum generation event May 13 as conditions changed.

The RTO said stakeholders were mixed in their reactions to the advanced alert.

Some stakeholders attending the RSC meeting questioned MISO calling conservative operations on a Friday for tight operating conditions on Monday. They said weather forecasts beyond 36 hours become unreliable and predicting load patterns so far in advance is an uncertain business.

But Van Schaack said this May was likely the RTO’s warmest on record, especially in MISO South. He predicted more emergency operating procedures over summer, in accord with the RTO’s official spring predictions. (See MISO: Summer Reserves Adequate, but Emergency Likely.)

“The footprint capacity margin is tighter, and we anticipate more emergency procedures,” Van Schaack said. He asked stakeholders if MISO should add a communication step “to improve awareness” prior to issuing a maximum generation alert.

Following emergency conditions during an extreme cold snap in January, multiple stakeholders asked the RTO to distribute more real-time electronic communication to its members when it faces near-emergency or emergency conditions. (See MISO Breaks down Recent Cold Snap.)

But some stakeholders at the meeting pointed out that declaration of a maximum generation alert might already pre-empt any plan to create an additional emergency notice, as an alert is issued before a maximum generation warning, which is followed by declaration of a maximum generation event when conditions worsen.

“To go into an alert, you do have to go into conservative operations. … We need to discuss the implications of more frequently going into conservation operations,” Van Schaack said, asking stakeholders to provide written feedback on an intermediary communication before a maximum generation alert. He also noted stakeholders could suggest MISO adopt no change to its emergency notice system.

Stakeholders pointed out that the RSC doesn’t hold another meeting until Aug. 2, which is likely to be well after the summer peak. Van Schaack responded that MISO would by then have more past alerts and emergency conditions to review and determine the best approach with stakeholders.

“Part of the reason we’re here is that it’s going to be hot in a few days. We’ll have a few opportunities to try things out,” Van Schaack said.

LMR Performance in January

MISO has concluded that it could improve its load-modifying resource performance after completing a detailed evaluation of the mid-January emergency, which identified issues with LMRs communicating their availability.

While the RTO requested 700 to 900 MW of LMRs throughout the emergency, it only received the requested amounts during five of the 10 hours of the emergency, with just 70% of LMRs that were called up by MISO meeting measurement and verification criteria. LMRs met scheduling instructions in 23 of 161 LMR interval hours, MISO said, while two LMRs missed instruction signals altogether. In total, the RTO assessed $123,000 in penalties to six market participants for underperformance, MISO Manager of Resource Adequacy John Harmon said.

Harmon said market participants continue to provide inaccurate LMR availability reports to MISO operators.

“There continues to be a trend of the load reduction availability in the MISO communication system not matching up with actual load reduction capability,” he said.

Vistra Energy’s Mark Volpe asked Harmon to give overall LMR performance during the event a letter grade.

“I’ll give it an elementary grade: ‘needs improvement,’” Harmon replied.

But Customized Energy Solutions’ Ted Kuhn asked the RTO to grade LMRs in terms of “how many megawatts were requested and how many were received,” not simply the “yes or no” of whether LMR volume was met in a specific hour.

MISO recently released a white paper documenting LMR characteristics in order to evaluate a growing reliance on LMRs in the footprint. The RTO concluded that it rarely sees the volume of LMRs that clear in the Planning Resource Auction made available in real time. The white paper recommended MISO take steps to:

Increase awareness of when market participants voluntarily call on their LMRs;
Ensure accurate reporting of LMR availability in the communication system;
Consider price incentives for LMRs;
Ensure MISO’s notifications are in tune with actual LMR need, with special attention on LMRs that require a 12-hour notification before responding to emergencies; and
Contemplate mandatory LMR access outside summer, the only season that LMRs are required to respond to emergencies.

MISO relies on LMRs’ self-reported availability in the communication system in both summer and non-summer months.

Executive Director of Market Operations Jeff Bladen said the RTO will re-evaluate LMR rules and requirements as part of its larger effort to respond to changing resource availability. (See MISO Looks to Address Changing Resource Availability.) Bladen said “it may be true” that MISO could end up needing something more than LMR response to meet increasing regularity of emergency conditions.

June 5, 2018

FERC: AEP Must Divulge Plant Data to PJM IMM

By Robert Mullin

American Electric Power must provide PJM’s Independent Market Monitor with requested cost data for a gas-fired plant the company owns in West Virginia, FERC ruled Tuesday (EL17-22).

In October 2016, the Monitor asked AEP to furnish the variable operations and maintenance (VOM) cost data the company used to develop its Sept. 1, 2016, cost-based offer for the 505-MW Ceredo generating station. The Monitor said it was seeking the data to determine whether the level of the cost inputs for the plant raised market power concerns in PJM’s energy markets.

AEP FERC Market Monitor PJM Incremental Costs — Ceredo Generating Station | *AEP*

Attachment M of PJM’s Tariff authorizes the Monitor to “review upon its own initiative at any time” the incremental costs included in a generator’s offer price cap to ensure the seller is complying with the RTO’s cost development guidelines. The Tariff also permits the Monitor to “make reasonable requests” for additional cost information from a seller after providing “an explanation of the need for the information and the [Monitor’s] inability to acquire the information from alternate sources.”

Attachment M also stipulates the Monitor can initiate legal or regulatory proceedings to compel disclosure, including petitioning FERC, if requested information is not provided within a reasonable amount of time. The Monitor filed its petition in November 2016.

AEP asked FERC to dismiss the Monitor’s petition, arguing it “is not about the exercise of market power or any violation of a Tariff provision or market rule” but instead focused on the Ceredo plant’s VOM calculation, which was then subject to a broader pending dispute before the commission regarding day-ahead offers that vary by hour (ER16-372, et al.).

Rather than probing market power concerns, AEP contended, the Monitor is really seeking to impose a VOM standard that differs from PJM’s current rules. The company noted the Monitor and PJM have taken opposing positions related to the appropriate calculation of VOM costs in the hourly offers docket. If the Monitor wishes to pursue changes to the calculation, it should pursue the FERC-approved process set out in Attachment M, the company argued.

But the Monitor “should not be permitted to make an example of AEP for purposes of advancing its agenda to impose the ‘short run marginal cost’ standard,” the company said.

AEP also argued the Monitor’s request for information was not reasonable given it had neither identified a potential market rule violation nor alleged the company had exercised market power. Furthermore, the burden of producing the request information outweighed any benefit, and the IMM’s effort is an impermissible audit, the company said.

Drift

In its comments to FERC, PJM largely sided with AEP’s position, contending that the Monitor is seeking to compel AEP to provide data supporting the exact type of costs the Monitor has called into question in the hourly offers docket. The ongoing conflict stemming from that proceeding prompted PJM to initiate a stakeholder process over the issue.

“To the extent the IMM would seek to refer AEP to the commission Office of Enforcement while the very matter itself is being contested before the commission on a generic basis, issues could arise as to the relationship of such referrals to the commission’s formal process, pursuant to [Federal Power Act] sections 205 and 206, to take comments on and ultimately rule on proposed tariff submittals based on a formal written record,” PJM said.

The RTO urged FERC to “provide guidance” on whether the Monitor’s request is reasonable “both in type and scope” to avoid future disputes and assure market participants “that the IMM’s authority to make requests for information is not boundless.”

The RTO also asked the commission to require the Monitor “to explain how the information it seeks relates to concerns other than the disagreement it has with how the PJM rules regard short-run marginal costs, adding it has concerns that the Monitor could “drift” into auditing market participants.

Commission Decision

But FERC’s ruling came down solidly in favor of the Monitor, noting that it has “broad authority” to review cost inputs and incremental costs and that its request for Cerredo’s total VOM costs — including identification of costs by category — was reasonable.

The commission also dismissed the concerns of both AEP and PJM regarding the potential conflict with the parallel hourly offers proceeding.

“The pendency of a PJM stakeholder process to clarify certain aspects of the PJM rules governing cost-based offers does not render unreasonable this specific request for cost data. The IMM retains its ongoing authority and responsibility set forth in Attachment M to review sell offers, cost inputs and incremental costs,” the commission said.

“In response to concerns that the IMM may be seeking to impose a cost standard that is inconsistent with the PJM Tariff or current PJM rules, we note that the IMM does not have the authority to enforce the PJM Tariff or PJM rules,” FERC concluded.

The commission directed AEP to provide the Monitor the requested cost information within 15 days of the order.

June 5, 2018

UPDATED: FERC Blindsided by Half-Baked Trump Order

By Rich Heidorn Jr.

WASHINGTON — FERC was given no advance notice of President Trump’s directive Friday ordering Energy Secretary Rick Perry to prevent further nuclear and coal plant retirements and has been provided no details since, officials said Tuesday.

FERC DOE Trump Rick Perry Kevin McIntyre — Menezes | © *RTO Insider*

FERC Chairman Kevin McIntyre and Department of Energy Undersecretary Mark Menezes had few answers for reporters’ questions in brief press conferences after speaking at the Energy Information Administration’s 2018 Energy Conference in D.C. on Tuesday morning.

Menezes told reporters DOE is still working out the details of the plan. He said the department would not necessarily be ordering RTOs and ISOs to purchase energy or capacity from at-risk plants — as was detailed in a DOE memo leaked last week — but that it was one of the options under review.

“We’re still evaluating the problem and what the options are,” Menezes said. “It was a leaked document that was in the process of being drafted.”

He did not respond when asked why Trump had made the directive last week when the details were uncertain.

Kevin McIntyre FERC DOE Trump Rick Perry — McIntyre | © *RTO Insider*

McIntyre told reporters that he has not been briefed by DOE nor seen a list of plants that might be affected.

“We had no idea” the directive was coming Friday, an exasperated senior FERC official told RTO Insider afterward.

Asked about DOE’s contact with FERC, Menezes said, “We talk to FERC on a fairly regular basis. We have not got into any specific proposals with FERC because we’re still working on specific proposals.

“This is a process that is bigger than the Department of Energy. … We’re getting input from all of … the agencies as to how they assess this,” he continued — an apparent reference to the National Security Council’s Policy Coordinating Committees. FERC is not a principal in the process.

McIntyre said the Trump administration’s directive is within the law under Federal Power Act Section 202c.

“The opening phrase uses something along the lines of, ‘In a time of continuing war’ … and so it has the feel of a kind of a wartime emergency. It then does go on …to have more inclusive emergency-type or urgent circumstances-type language that in my view avowedly could be invoked to capture this situation,” he said. “That is a decision not for me or anyone at the FERC, but rather for the secretary of energy.”

FERC Role in Question

McIntyre said FERC might not be involved in setting prices on rescued generators if they can reach agreements on compensation with RTOs.

“Under the [Federal Power Act] as it’s written, and the regulations of the DOE, there are different scenarios that could develop that would not involve a rate proceeding before the FERC. We’re looking at those details now as you can imagine.”

If FERC is not involved, the contracts would be judged on an “easier standard” than FERC’s traditional determinations of “just and reasonable,” he said.

[Editor’s Note: An earlier version of this article incorrectly quoted the chairman, saying FERC would use a lesser standard. A FERC spokeswoman said that was incorrect but that she did not know who would enforce the lower standard for settlements.]

McIntyre also discussed Trump’s directive in response to audience questions moderated by EIA Administrator Linda Capuano after his speech to the EIA conference.

If the 202c “trigger is pulled,” McIntyre said, generating plants could attempt to work out a contract with the entity providing it compensation. “If that effort should fail, then the matter could [come] up to the FERC for what FERC would regard as — for lack of a better term — a rate case … which the FERC has been handling for decades. So, from that standpoint it wouldn’t be a dilemma. In a sense it would almost be bread and butter. We’d have to figure out how to get the dollars and cents right, that would be probably the biggest [challenge]. We’ve got a very talented staff” to do that.

“If it comes to us a rate proceeding it would indeed be subject to [just and reasonable],” McIntyre added in the press scrum later. But a contract negotiated between an RTO and a generator — “something [that’s] worked out almost in a settlement fashion [is] subject to … effectively an easier standard … fair and reasonable,” he explained.

Asked whether FERC would have to mitigate the impact of power plant subsidies on the wholesale markets, the chairman responded, “I think there are a number of different ways we could approach it as long as we’ve satisfied ourselves that it meets our standards of justness and reasonableness.”

McIntyre said he didn’t know whether the directive would affect the resilience rulemaking FERC opened in January after rejecting Perry’s Notice of Proposed Rulemaking to provide cost-of-service payments to coal and nuclear plants with on-site fuel. The NOPR was submitted under Section 403 of the Department of Energy Organization Act. (See FERC’s Independence to be Tested by DOE NOPR.)

‘Not a New Issue’

In his remarks to reporters earlier, Menezes indicated the policy initiative was far less settled than the memo suggested. He said there is no deadline for DOE’s next step.

Asked whether ordering capacity and energy purchases — as spelled out in the memo — was the main option under consideration, he said DOE is considering “as many [options] as people can come up with. … It’s an iterative process.”

“This is not a new issue that we’ve been trying to address. Right?” Menezes continued. “I mean, we sent a [Section] 403 letter over to FERC … We’ve identified this issue for some time. So, we have continued to look at our options.”

“Why did the president announce this Friday if you don’t know what you’re doing?” Menezes was asked.

“I didn’t say we don’t know what we’re doing. I said we are considering options, is what we’re doing,” he responded. “We want to make sure that whatever we do works and is upheld by courts.”

coal trump rick perry ferc kevin mcintyre — Menezes addressing attendees at this year’s EIA Annual Conference | © *RTO Insider*

The undersecretary dismissed the suggestion that the administration is threatening to disrupt RTO power markets. “FERC has to figure out a way to keep the so-called ‘markets’ operating. But they are voluntary,” he said.

“These markets have not been mandated by Congress. … It’s important for the RTOs to keep their states happy. If the states are not happy with the RTOs in which they participate, the RTOs won’t exist. … These are not natural markets. In fact, electricity is a natural monopoly,” he said.

Losing ‘Energy Security’

During his address to the EIA conference, Menezes decried the grid’s “growing dependence on pipeline-dependent and intermittent resources,” noting that there are no mandatory reliability standards for gas pipelines.

He also said the premature closures of nuclear plants has Saudi Arabia and other nations “questioning our commitment to remain leaders in nuclear technology.” He said that has opened opportunities for South Korea, which won nuclear generation contracts with the United Arab Emirates, and China, which he said does not require clients to sign the antiproliferation protections the U.S. mandates.

“So, we’re losing more than grid resilience. We’re losing energy security,” he said. “… Imagine a world where the U.S. sits on the sidelines while other countries can dictate what other countries can do with their nuclear fuel. Think about that for a few minutes.”

June 5, 2018

No Details from Perry

Perry commented favorably on Trump’s directive in a speech at a DOE cybersecurity conference in Austin, Texas, Monday but did not elaborate. “Fuel-secure units are retiring at an alarming rate that — if unchecked — will threaten our ability to recover from intentional attacks or from natural disasters,” Perry said. “The president is right to view grid resilience as a serious national security issue, and he’s directed me to prepare immediate steps to stop the loss of these critical resources.”

PJM and MISO officials said Monday they were caught off guard by President Trump’s directive Friday and said they had received no information since then.

“At this time, we have seen no official communication from DOE,” said Shawna Lake, MISO’s senior director of communications and stakeholder affairs.

“I saw it when it flew in my inbox Friday,” Craig Glazer, PJM’s vice president of federal government policy, said before speaking at the EIA conference Monday.

FirstEnergy’s Lobbying Bill Revealed

Perhaps the most interesting development in the story Monday came from the Energy and Policy Institute, which published a blog post on a new filing in the bankruptcy case for FirstEnergy Solutions. The 174-page report shows Akin Gump billing FES $3.8 million in fees and expenses during April, including more than $753,000 in fees for “Energy Regulatory Issues” and federal and state “Government Affairs” work.

Akin Gump billed FirstEnergy Solutions $3.8 million in fees and expenses during April, including more than $753,000 in fees for work on “Energy Regulatory Issues” and federal and state “Government Affairs” work. | *Energy Policy Institute*

Including the $230,000 Akin Gump disclosed in a federal lobbying report for January-March, it has billed FES almost $1 million in lobbying expenses since January.

On April 13, for example, lobbyist James Romney Tucker, a former aide to Newt Gingrich, reported a “call to DOE re potential 202c determination” and a “call with White House staff re 202 status.” Tucker alone billed FES $54,312 at $930/hour for his “Public Law & Policy” work during April.

The institute is a self-described watchdog “exposing the attacks on renewable energy and countering misinformation by fossil fuel interests.” Akin Gump is D.C.’s top-earning lobbying firm.

Lifeboat Revived?

One RTO official who asked not to be identified suggested the administration’s plan may be like the “lifeboat” then-acting FERC Chairman Neil Chatterjee suggested last November in response to DOE’s Notice of Proposed Rulemaking, which the commission rejected in January. Chatterjee had contemplated a “show cause” order requiring grid operators to compensate at-risk resources that provide resilience benefits as an interim measure while the commission conducted a longer-term rulemaking. (See Chatterjee to Push Interim ‘Lifeboat’ for Coal, Nukes.)

Chatterjee had said his plan would not alter RTO dispatch practices or distort markets, though he acknowledged a lot of details remained undetermined. The idea was apparently forgotten after Kevin McIntyre joined the commission in December, replacing Chatterjee as chairman.

RTOs Caught in the Dark

RTO/ISO executives speaking at the Mid-America Regulatory Conference in Kansas City, Mo., Monday had similar reactions to the memo, with all offering assurances that reliability is well under control in their footprints.

Panel moderator and Missouri Public Service Commission Chairman Daniel Hall characterized the memo as a “possible intrusion into the markets” and asked executives for their reactions.

MISO President and Chief Operating Officer Clair Moeller said he thinks an order is unnecessary but added that the RTO keeps out of retirement decisions. He said the decision whether to close a plant in MISO is between the plant owner and the state in the mostly vertically integrated footprint. “We like to say we’re policy takers, not policymakers,” Moeller said.

However, he offered that the proposed 90 days of on-site fuel supply is not a historical standard. “We’ve never had 90 days of coal on site in the 40 years I’ve been in the industry,” Moeller said. He offered that resilience is “how you take the stuff you have and make it work to keep people safe.”

SPP Executive Vice President and Chief Operating Officer Carl Monroe also said his mostly vertically integrated RTO likely won’t see plants directly impacted, though an order could cause energy prices to rise in its footprint.

“I don’t think I get to say that it won’t affect us,” laughed Suzanne Daugherty, PJM’s chief financial officer and treasurer, noting that most states in the RTO’s territory have adopted retail choice.

But she said PJM will exceed its current resource adequacy standards in the foreseeable future. “We’ve done the planning studies, and we’re going to hit targets well above what we were trying to reach.”

FERC DOE AKIN GUMP CHERYL LAFLEUR — Left to right at MARC’s 2018 Annual Conference: Carl Monroe, SPP; Suzanne Daugherty, PJM; and Bill Magness, ERCOT | © *RTO Insider*

The move is a “drastic step” that could become a financial burden for ratepayers, Daugherty said. “Each type of resource, whether it’s intermittent, hydro, coal, nuclear, all have [fuel supply] issues.”

She also said it would be a “challenge” for independent power producers to make queue investment decisions if generators expected to retire instead begin receiving revenue streams. She pointed out that PJM has already initiated a fuel security study to examine how efficiently fuel is delivered to all plant types during times of peak demand.

ERCOT CEO Bill Magness said he is waiting on the full order to understand the possible impacts. “We’re not sure if this is applicable to ERCOT,” Magness said. “The Defense Production Act is not something I’m that familiar with, but I’m learning about it now,” he added, smiling.

“We’re trained to run security-constrained economic dispatch,” Magness said. “And if this [order] fits into security-constrained economic dispatch, well, we can do that.” But he cautioned that fuel security issues — like ensuring rail cars arrive on time — is outside of ISO/RTO control.

TRUMP Rick Perry FERC DOE AKIN GUMP CHERYL LAFLEUR — Glazer | © *RTO Insider*

PJM’s Glazer told the EIA conference Trump’s directive will “probably complicate” his RTO’s struggle to deal with state nuclear subsidies.

He said he fears a “half slave/half free” industry in which generators dependent on market revenues increasingly compete with those receiving cost-of-service payments or subsidies.

“I’m not sure that’s sustainable, to be honest,” he said. “I worry as we move down this path that we’re ignoring the lessons of the past” — the 1970s, before electric restructuring.

June 3, 2018

Calif. Senate OKs Utility Wildfire Cost Recovery

By Jason Fordney

The California State Senate passed legislation Wednesday that would allow the state’s investor-owned utilities to pass through the costs of wildfires to ratepayers if they conform with safety plans approved by the Public Utilities Commission.

Wildfire Cost Recovery CPUC California Senate — Dodd | *U.S. Army Corp. of Engineers*

SB 1088, introduced by Sen. Bill Dodd (D), would require electric and gas utilities beginning in 2019 to submit annual safety, reliability and resilience plans, which the commission could approve “with or without modification” within 18 months.

If a utility is in compliance with its plan, “the utility’s performance, operations, management and investments addressed in the plan may be deemed reasonable and prudent for purposes of any subsequent CPUC proceeding and are prohibited from affecting any civil action and any previous events.”

Dodd said that “by mandating that utilities meet new safety, reliability and resiliency requirements, we can avoid these catastrophic fires before they start.” He introduced the legislation in April. (See Calif. Legislation Shields Utilities from Wildfire Costs.)

The bill passed the Senate on Wednesday on a 34-2 vote with three legislators not voting, including U.S. Senate candidate Kevin de Leon (D). Friday was the deadline for bills to pass out of their house of origin. The deadline for bills to be passed this year is Aug. 31, and the last day for the governor to sign or veto them is Sept. 30.

The measure comes amid a decade-long debate over utility liability for wildfires, which heightened last year as more than 170 fires swept across California. The Department of Forestry and Fire Protection recently found that Pacific Gas and Electric had caused four Northern California fires, and investigations continue into much larger fires that hit the state last year. (See CalFire Says PG&E Caused 4 Wildfires Last Year.)

Utilities argue that climate change and drought are compounding the effects of the fires. Some observers also blame forest management practices for exacerbating the problem. Last November, the CPUC rejected San Diego Gas & Electric’s request to recover $379 million in wildfire-related costs for fires in 2007, drawing swift reaction from all three of the state’s investor-owned utilities. (See Besieged CPUC Denies SDG&E Wildfire Recovery.) In addition to their concerns over recovering fire costs, utilities also face civil suits by property owners blaming the power companies for fire losses.

The bill would require the state Office of Emergency Services to adopt standards and model policies that utilities and local governments should employ for reducing fire risks, including defining “defensible space.”

The Utility Reform Network had opposed the bill, saying that “rather than enhancing safety, SB 1088 would reduce current energy utility incentives to operate their systems safely and prudently and would effectively grant the utilities a blank check,” according to a May 29 bill analysis.

The Consumer Federation of California said that the 18-month CPUC timeline “undermines the possibility for a review that is fully vetted by the regulator and the public” and that the legislation “leaves almost no room for the regulator to reject a utility plan.”

Another Dodd bill passed by the Senate on Thursday, SB 901, requires utility wildfire mitigation plans to include a description of the factors the companies use to determine when they should de-energize distribution lines and procedures for notifying customers and first responders, who could encounter live lines.

Dodd’s two proposals were part of a seven-bill package approved by the Senate last week, which also dealt with homeowner insurance coverage, controlled burns and landslides. President Pro Tempore Toni Atkins (D) said the Senate has also proposed a budget that includes $483 million for fire-prevention efforts and $551 million for wildfire mitigation.

June 3, 2018

DC Circuit Rejects Ark. PSC Review of FERC-Entergy Order

By Tom Kleckner

The D.C. Circuit Court of Appeals on Friday denied the Arkansas Public Service Commission’s request that it review a 2016 FERC order directing Entergy Arkansas to continue sharing settlement proceeds under the Entergy System Agreement (16-1305).

FERC approved Entergy Arkansas’ withdrawal from the agreement in 2009. In 2016, FERC held that the utility must continue to share the proceeds of its predeparture settlement with Union Pacific with the system’s other member companies (ER13-432).

The PSC contended that the commission’s order to share the settlement benefits and its method of allocating the benefits was unlawful and unsupported by substantial evidence.

The D.C. Circuit concluded that FERC had a lawful basis to order the sharing of the benefits and was “reasoned” in its allocation methodology.

The PSC pointed to Entergy Arkansas’ withdrawal proceeding in arguing that FERC’s order “essentially amounts to the imposition of an unlawful exit fee or post-withdrawal continuing obligation.”

Writing for the three-judge panel, Senior Circuit Judge David Sentelle rejected the argument, saying FERC was right to conclude “that sharing the Union Pacific settlement benefits was necessary under the principles of equity and was not a penalty or recompense for the company’s exit from the system.”

The court also disagreed with the PSC’s contention that FERC violated the filed rate doctrine by ordering Entergy Arkansas to share the settlement benefits. Under that doctrine, public utilities may only charge rates filed with FERC.

Sentelle said FERC had determined it was not overriding a filed rate, “but merely effectuating the purpose of a non-jurisdictional contract.” He noted Entergy Services was a party to the settlement, and that “FERC found [Services] entered into the settlement on behalf of all the operating companies while they were under FERC’s jurisdiction through the system agreement.”

The court also agreed with FERC’s use of its allocation method, noting the commission found it likely “Entergy Arkansas would have entered into a multiyear transportation contract in 2011 and not benefited from [a] price dip in 2012” without the Union Pacific settlement.

“There was no evidence that Entergy Arkansas could have anticipated the 2012 drop in coal transportation prices and made different contracting decisions,” Sentelle said.

The proceeding stemmed from a 2008 settlement in Arkansas state court between Entergy Arkansas, Entergy Services and other parties against Union Pacific. The settlement locked in a below-market rate for rail delivery of coal by extending an Entergy Arkansas contract with Union Pacific to a three-year period ending June 30, 2015.

Under Entergy’s system agreement, which expired in 2016, its operating companies purchased excess energy from their sister companies at cost, incorporating coal transportation as a component. Union Pacific failed to make coal deliveries at one point, leading to the settlement.

Entergy Arkansas passed a portion of the increased coal costs to the other operating companies under the agreement’s service schedule, and also shared its beneficial coal transportation costs under the Union Pacific settlement.

However, the settlement did not address Entergy Arkansas’ impending withdrawal from the agreement, which FERC approved in 2009.

The Louisiana Public Service Commission filed a Section 206 complaint with the commission, arguing that FERC should allocate the Union Pacific settlement benefits as part of the case. The D.C. Circuit eventually upheld the commission’s decision, but it held FERC “must still review the post-withdrawal arrangements.”

The Louisiana commission again raised the Union Pacific issue when Entergy Services filed a post-withdrawal successor plan with FERC. In response, the Arkansas commission and Entergy Services challenged FERC’s authority to order Entergy Arkansas to share the settlement benefits, because the utility was no longer participating in the system agreement.

Following settlement discussions and a hearing, an administrative law judge determined that the settlement benefits should be allocated among the operating companies and adopted an allocation methodology. FERC affirmed the findings in 2016 and ordered Entergy Arkansas to make a compliance filing refunding the settlement benefits to its sister companies.

June 3, 2018

Analyst: FERC Asserts Role in Handling Nuke Subsidies

By Rory D. Sweeney

FERC and the U.S. Department of Justice struck a blow against opponents of state subsidies for nuclear plants on Tuesday when they jointly filed a brief urging the 7th U.S. Circuit Court of Appeals to reject the argument that Illinois’ zero-emission credit program is pre-empted by the Federal Power Act.

But an analyst for an industry law firm believes the brief, which was quickly cross-filed by Exelon in a similar case in New York before the 2nd Circuit, has a deeper meaning: Leave this to us.

“FERC made clear that ‘we have jurisdiction under the Federal Power Act to deal with what we view as states subsidizing these generation facilities,’” Jennifer Mersing of Stoel Rives told RTO Insider. “I think FERC was saying essentially, ‘We are handling this. … Let us be the forum where this gets worked out.’ They didn’t tip their hand about how they would rule … but I think that FERC is trying to keep within its court how it’s going to deal with states subsidizing certain nuclear facilities.”

The Electric Power Supply Association and retail ratepayers asked the courts to overturn district court rulings last year that dismissed challenges to the states’ ZEC programs. They argued that the state laws were stripping FERC of its authority over the sale of wholesale energy. (See Ill. ZECs Defenders Face Harsh Questioning on Appeal.)

“The Illinois program is not pre-empted,” FERC and the Justice Department said. “It does not require participation in FERC-jurisdictional wholesale auctions as a precondition to receive ZECs. Rather, the Illinois ZEC is ‘targeted’ at an attribute of generation resources over which Illinois has regulatory authority. … The object of the subsidy is the ‘participant,’ not the ‘actual wholesale transaction.’ The district court thus properly concluded that the ZEC program ‘falls within Illinois’ reserved authority over generation facilities.’”

Exelon, which owns five nuclear facilities that stand to benefit from the laws, joined the states in their defense and lauded the brief’s filing.

ferc zero emission credits zecs federal power act — Exelon’s Clinton nuclear facility, which benefits from Illinois’ zero-emissions credit program. | *Nuclear Regulatory Commission*

“The U.S. Department of Justice and Federal Energy Regulatory Commission told the courts that states are free to favor clean nuclear energy over pollution-emitting energy from coal, oil and natural gas power plants,” the company said in a statement. “We remain confident that the courts will uphold the view of policymakers and regulators who support the continued operation of Illinois’ nuclear plants and the environmental benefits they provide for consumers.”

Mersing agreed the brief would likely tip the court’s decision in favor of the states and leave FERC to address the issue. Judges in the Illinois case had previously questioned why EPSA was bringing the issue to them when they were simultaneously pleading their case with FERC, which noted in its brief that it will address complaints pending on the issue.

“It’s hard to quantify … but I think that if you have the agency in charge of regulating wholesale power sales [saying it] doesn’t view this law as being pre-empted by the statute it’s in charge of enforcing, I think that’s going to weigh heavily,” Mersing said. “I think the court was probably waiting for FERC to weigh in, so I would expect a decision would come sooner, but we can’t predict when the court will act.”

She predicted the courts will likely uphold the laws, making it unlikely the Supreme Court would take up the case if EPSA were to continue its appeal. The decisions will likely signal other states to pursue similar nuclear subsidies but keep them funneled through FERC, she said.

“You’ll see more states following the path because it removes some legal challenges, but it also depends on how FERC decides to handle the programs,” she said. “I think you’re going to see more complaints at the FERC level versus the federal court level.”

EPSA has requested permission to respond to the brief by June 9, which Exelon has opposed.

June 3, 2018

PJM Experiences First Load Shed in the CP Era

By Rory D. Sweeney

PJM ordered its first load-shed event since implementing Capacity Performance in 2015 after a transmission line in Indiana tripped offline on May 29.

It was also the RTO’s first trigger for the significant performance-related bonuses and penalties introduced with CP.

pjm capacity performance load shedding — PJM’s Adam Keech | © *RTO Insider*

The 30-minute event occurred at the Jackson Road substation in American Electric Power’s transmission zone, west of South Bend, Ind. PJM’s Adam Keech explained that a transformer and a transmission line unexpectedly tripped out of service about 1:20 p.m., creating a load on the facility above its ratings.

As part of its response procedures, PJM simulated the effect on the system of losing that facility. The RTO’s procedures call for continuing that analysis for facilities that subsequently would become overloaded and simulating their loss as well. If that continues for five steps without mitigation, or if it hits a larger issue and can’t be resolved, PJM pre-emptively sheds load “before anything else tripped that would potentially create a cascading outage,” Keech said during a special Markets Implementation Committee meeting Friday on updating the variable resource requirement curve.

For this situation, grid operators ordered a reduction of 71 MW of load, he said. However, the transformer kicked back into service, “so the total requested amount was never actually shed … because the equipment came back that quickly.”

No demand response was called, Keech said. PJM later confirmed the actual load shed was 21 MW.

The situation triggered the first performance assessment interval (PAI) under the CP capacity construct, which analyzes the performance of generators that were paid for a capacity commitment to supply power in that region. Units that outperformed their commitments are eligible to receive bonus payments, while those that underperform receive stiff financial penalties. The analysis compares the supply needed to the units that have commitments and only includes units that were able to help by raising their output, Keech said.

PJM is limited in how much information it can release, he said, because the event affected only a small number of generation owners. The RTO’s confidentiality rules restrict what information staff can release if fewer than four generation owners were affected, he said.

Keech noted that some stakeholders expressed concerns with how the incident was communicated and said staff plan to revise procedures to address them.

“I think when we envisioned PAIs, the discrete, very localized load-shed event wasn’t on everybody’s mind. But now that we’ve got it, we should learn to handle it a little bit better,” he said.

The event will have implications for several other markets and reliability calculations, including the balancing ratio and default market seller offer cap. (See “Balancing Ratio,” PJM Market Implementation Committee Briefs: May 2, 2018.)

June 3, 2018

CPUC Approves Utility EV Infrastructure Programs

By Jason Fordney

California regulators last week authorized the state’s investor-owned utilities to recover $738 million for electric vehicle charging infrastructure to help meet the state’s greenhouse gas reduction goals.

The California Public Utilities Commission’s Thursday order stemmed from its 2016 directive ordering the IOUs to propose projects that would advance the electrification of transportation. During the proceeding, the state’s Office of Ratepayer Advocates and The Utility Reform Network negotiated aspects of the program, originally proposed at $1 billion by the utilities.

CPUC electric vehicles charging infrastructure EV — Peterman | © *RTO Insider*

“The only way to get to a largely carbon-free California is by substantially electrifying the state’s vast transportation system,” Commissioner Carla Peterman said. “The decision made today aims to balance costs with benefits for all ratepayers, considers impacts on competition, and directs significant portions of the utility programs to disadvantaged communities often hit hardest by traffic and air pollution.”

The Natural Resources Defense Council supported the CPUC’s decision, saying it “marks the nation’s single largest investment by the electric industry to eat away at Big Oil’s longtime monopoly over transportation fuels.”

Each IOU had its own package approved by the commission.

San Diego Gas & Electric: A $137 million rebate program for 60,000 Level 2 home-based charging stations, and an EV-only variable hourly energy rate.
Pacific Gas and Electric: $22 million for a “Direct Current Fast Charging Make-Ready Program” supporting 234 fast-charging stations at 52 sites. Also approved was make-ready infrastructure at a minimum of 700 sites to support the electrification of at least 6,500 medium- or heavy-duty vehicles.
Southern California Edison: $343 million to install the make-ready infrastructure at a minimum of 870 sites to support the electrification of at least 8,490 medium- or heavy-duty vehicles, and three new time-of-use rates for commercial customers with electric vehicles.

Make-ready infrastructure includes service connection and supply infrastructure to support EV charging. It is composed of the electrical infrastructure from the distribution circuit to the stub of the EV charging station and can include equipment on the utility side, such as a transformer, or on the customer side, such as electrical paneling or wiring of the meter, the CPUC said.

The commission modified some of the budgets and terms of the program. For example, it rejected SDG&E’s proposal to include existing EV customers in its program. TURN had argued that existing EV customers would be free riders, pointing to a survey that indicated 76% of California EV drivers have income of $100,000 or more. The commission included provisions for disadvantaged communities, setting rebates and adoption targets for EVs in those areas.

California’s Clean Energy and Pollution Reduction Act of 2015 set new greenhouse gas reduction goals and directed the CPUC to work with other agencies to advance the electrification of transportation.

The CPUC began the proceeding in July 2017 and conducted 11 days of hearings last fall. Other parties included environmental groups, the California Transit Association, Union of Concerned Scientists, EV infrastructure companies and consumer groups.

The decision came just after the California Energy Commission issued a report saying the state will need between 229,000 and 279,000 EV chargers at locations other than single-family homes by 2025 to meet the state’s goals for adoption of zero-emission vehicles. (See California to Require Sharp EV Charger Growth by 2025.)

June 1, 2018

AEP Wind Catcher Project Notches Regulatory Wins

By Tom Kleckner

American Electric Power’s massive Wind Catcher Energy Connection project in the Oklahoma Panhandle continues to rack up regulatory wins.

On Wednesday, independent transmission company GridLiance and Tri-County Electric Cooperative announced they have joined a settlement agreement with AEP related to the company’s proposed 2-GW, $4.5 billion project.

Meanwhile, a Texas administrative law judge has issued a proposed decision approving AEP’s application before the state’s Public Utility Commission. The PUC will take up the proceeding at its July 12 open meeting (Docket No. 47461).

Under the settlement’s terms, GridLiance subsidiary South Central MCN will have the option to construct, own and operate any additional Wind Catcher interconnections in Tri-County’s panhandle service territory of Cimarron, Texas and Beaver counties. The agreement will also provide protections guaranteeing that AEP subsidiary Public Service Company of Oklahoma (PSO) will not provide retail service in Tri-County’s certified service territory for 25 years after the project begins commercial operation.

South Central and Tri-County, along with the Oklahoma Municipal Power Authority and Oneta Power, have now joined with Oklahoma Industrial Energy Consumers and Walmart in reaching settlement agreements with PSO on Wind Catcher.

wind catcher Gridliance Sri-County AEP — Tri-County Electric Co-Op’s Service Territory | *TCEC*

The parties are requesting that the Oklahoma Corporation Commission approve the terms of the agreements. PSO said the terms “collectively result in significant customer savings guarantees and increased use of natural gas power” generated in Oklahoma. (The recent agreements include a new power purchase agreement with Oneta for 300 MW of gas-fired energy and capacity beginning in 2022.)

Dallas-based GridLiance said agreeing to the settlement will allow it to “adequately plan and operate its existing transmission system and future interconnections for the benefit of its utility partners.” Those partners included Tri-County, which will also retain the right to serve retail electric load in its service area.

The co-op’s CEO, Zac Perkins, said the right to serve retail load will last for the life of the Wind Catcher project.

“By partnering with GridLiance on this settlement, we were able to secure the rights to defend the service territory of our retail customers,” Perkins said.

Wind Catcher AEP GridLiance Tri-County — Crowder | © *RTO Insider*

GridLiance CEO Calvin Crowder said the company was pleased with the settlement.

“The panhandle’s economic development depends on a reliable local transmission system that serves multiple needs, and GridLiance remains committed to serving those needs now and in the future,” he said.

GridLiance, which focuses on collaborating with public power entities, entered into an agreement with Tri-County in 2015 to plan, construct and operate transmission infrastructure projects in the panhandle. (See GridLiance Makes First Acquisitions.)

PSO CEO Stuart Solomon said in a release that the agreements further demonstrate that Wind Catcher is good for customers.

“The agreements guarantee customers will save money and allow us to move forward with our plan to increase use of Oklahoma-based renewable energy and natural gas generation to provide affordable, reliable service to our customers,” he said.

PSO is seeking regulatory preapproval to recover $1.36 billion in project costs. It has proposed to the OCC that it cap project costs at 103%, and it has guaranteed the project would qualify for 100% of federal production tax credits available when Invenergy began construction in 2016.

Wind Catcher would consist of an Invenergy-developed wind farm containing 800 2.5-MW turbines. A 360-mile, 765-kV line from the panhandle to Tulsa will connect the wind farm to PSO’s grid and that of sister company Southwestern Electric Power Co., which owns 70% of the project.

AEP says Wind Catcher will result in $7 billion in energy savings for its utility customers in Arkansas, Louisiana, Oklahoma and Texas. The Arkansas Public Service Commission has already approved the project, but it still awaits regulatory OKs in the other three states.

SWEPCO has filed an application before the Texas PUC to amend its certificate of convenience and necessity and authorize its interest in Wind Catcher, and for preapproval of various ratemaking treatments to recover the project costs. The utility estimates its share of the costs at approximately $3.2 billion, with $1.1 billion within Texas retail jurisdiction.

In recommending the project’s approval, Texas ALJ Henry Card relied on the precedent set by the commission’s recent approval of Southwestern Public Service’s wind farm in West Texas. In that proceeding, the commissioners overcame their concerns that SPS was requesting 478 MW of energy when it already had sufficient capacity on its system to meet demand. (See Texas PUC Issues Final Order for SPS Wind Farm.)

“Utilities may obtain a CCN for general economic purposes not just when there is an increase in demand necessitating additional generation,” Card said in his decision.