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January 11, 2019

ISO-NE, NEPOOL Answer Generators on FCM Test Price

By Michael Kuser

ISO-NE on Wednesday urged FERC to reject a pr o test filed by the New England Power Generators Association over the RTO’s proposed “test price” mechanism to be applied to resources seeking to retire capacity through the RTO’s substitution auction (ER19-444).

The complaint stems from the Nov. 30 joint filing by ISO-NE and the New England Power Pool proposing several Tariff changes to help implement the RTO’s Competitive Auctions with Sponsored Policy Resources (CASPR). FERC approved the RTO’s two-stage capacity auction designed to accommodate state renewable energy procurements last March. (See Split FERC Approves ISO-NE CASPR Plan.)

As part of the proposed changes, ISO-NE is seeking to introduce the concept of a test price that approximates a resource’s competitive price to acquire a capacity supply obligation.

“Without some mechanism to assure competitive bidding, stakeholders worried that a participant would have incentive to reduce its primary auction delist bid below competitive levels in order to clear the primary auction and, as a result, qualify for ‘severance’ payments in the substitution auction,” NEPOOL explained in a separate answer to NEPGA’s protest filed Jan 7.

The test price would “serve as a screen for competitive behavior in the primary auction to determine whether an existing capacity resource’s demand bid can enter the CASPR substitution auction,” according to the RTO. It is intended “to thwart uneconomic bidding behavior in the primary auction of the Forward Capacity Market that, if unchecked, could reduce the primary auction clearing price below its competitively based level.”

ISO-NE noted that its Tariff currently requires its Internal Market Monitor to make two annual filings with FERC showing various inputs for the Forward Capacity Auction slated for the following year. One of those filings, submitted each July, covers retirement delist bids from participants that intend to retire a resource.

“Since the CASPR test price is an auction input that is established as part of the IMM’s review of retirement bids (and uses largely the same formula specified in the current Tariff for calculating retirement delist bids), the CASPR-related changes contemplate the filing of the test price values as part of the July filing of the retirement bids,” the RTO explained.

While NEPGA does not oppose the filing of the test prices, it does contend that the IMM should be required to file participant-submitted test price values — not the values determined by the IMM.

NEPGA argued that prioritizing the IMM’s values would usurp a market participant’s sole right under the Federal Power Act to file a retirement delist bid as its rate for acceptance by the commission and that “the test price likewise is a rate, term or condition” of the participation in the FCA.

ISO-NE countered that NEPGA’s argument is an “abbreviated repeat” of arguments the organization made in a protest of the previous Tariff revisions related to market rules for retirement of resources.

“In that proceeding, NEPGA argued that the proposed Tariff changes denied market participants their Section 205 filing rights to seek a determination of their own rates by requiring the IMM to file, in the July retirements filing, the IMM-determined delist bid price for a retiring resource, rather than the delist bid price submitted to the IMM by the market participant,” ISO-NE said. “The commission squarely rejected NEPGA’s contention.”

The RTO said Section 205 rights are not at issue in the proceeding, “as the test price — like many other inputs into the auction — is not a rate, term or condition.”

NEPOOL contended that instead of “unnecessarily” disrupting the stakeholder process, NEPGA should have “appropriately presented an amendment to the test price mechanism” at stakeholder meetings, in which case “NEPOOL may have supported an alternative approach that could have assuaged NEPGA’s concern.”

While it participated in the stakeholder meetings, neither NEPGA nor any other stakeholder suggested this alternative proposal, NEPOOL said. Stakeholders considered and debated the entire package of CASPR-related changes over last summer before a final vote at the Participants Committee in November, it said.

Resolving the Mystery

In the same filing, the RTO also answered NEPGA’s Jan. 8 mot i on to lodge a Dec. 28 decision by the D.C. Circuit Court of Appeals (Exelon v. FERC, 17-1275) into the test price proceeding.

In the decision, the court remanded back to FERC its order accepting ISO-NE’s retirement delist bid mechanism in the FCA, based on the commission’s own explanation at oral argument that a market participant — and not ISO-NE or the Monitor — has the right to show that its filed rate is just and reasonable and will be entered into an auction regardless of the Monitor’s proposed offer price. (See FERC OKs Lower Delist Threshold in ISO-NE.)

“We see no way to skirt the question Exelon tees up: Under ISO-NE’s new Tariff rules, does a supplier’s rate enter the auction so long as it convinces the commission that the rate is just and reasonable, over contrary claims of the Market Monitor?” the court said.

It remanded the case to FERC “to resolve the mystery,” saying the commission “should issue its clarification expeditiously, and in no event later than Feb. 1, 2019.”

“NEPGA agrees with commission counsel that it is the market participant’s right and obligation to make that showing, and as it explained in its limited protest in this proceeding, the law likewise applies to the test price market participants will be required to file for acceptance by the commission if the commission accepts the test price design in this proceeding,” NEPGA said.

The RTO reiterated its contention that NEPGA’s assertions are an “abbreviated” recycling of prior arguments rejected by FERC and that “NEPGA has made no attempt in its protest to explain why the same assertions do not similarly fail when aimed at the test price mechanism.”

In addition, the RTO said the D.C. Circuit’s remand “decides nothing regarding the issues in contention here regarding the test price” and that “at this stage, therefore, there is nothing of relevance to be gleaned from the D.C. Circuit’s opinion.”

January 11, 2019May 8, 2025

EPSA Asks Supreme Court to Review ZEC Rulings

By Michael Kuser

Several power producers joined the Electric Power Supply Association on Monday in petitioning the U.S. Supreme Court to review appellate court rulings upholding the New York and Illinois zero-emission credit programs.

Last September, both the 2nd and 7th U.S. Circuit Courts of Appeals rejected claims by EPSA and others that New York’s and Illinois’ ZECs, respectively, intrude on FERC jurisdiction. (See Appeals Court Upholds NY Nuclear Subsidies and 7th Circ u it Upholds Ill. ZEC Program.)

EPSA on Jan. 7 petitioned the Supreme Court for writs of certiorari to review both decisions. The group was joined on the 2nd Circuit petition by NRG Energy, with the New York Public Service Commission and Exelon — and its three New York nuclear plants — named as defendants. Calpine joined the 7th Circuit petition in the case against the Illinois Power Agency, the Illinois Commerce Commission and Exelon.

Exelon’s Byron Generating Station’s two nuclear reactors in Illinois produce more than 2,300 MW of electricity.

Enough Percolation

The New York PSC created the ZEC program in August 2016 as part of its Clean Energy Standard, which set a goal of reducing greenhouse gas emissions by 40% by 2030.

The PSC said it designed the program to avoid the issues behind the Supreme Court’s April 2016 ruling in Hughes v. Talen, which voided Maryland regulators’ contract with a natural gas plant as an intrusion into federal jurisdiction over wholesale power markets. (See NY Attempts to Thread Legal Needle with Clean Energy Standard, Nuke Incentives.)

The 2nd Circuit said that ZECs, like renewable energy credits, are certifications of an energy attribute separate from the purchase or sale of wholesale energy. Although the ZEC program “exerts downward pressure on wholesale electricity rates, that incidental effect is insufficient to state a claim for field pre-emption under the” Federal Power Act.

The court noted that the PSC avoided the defects of the Maryland contract for differences, which required the generator to participate in PJM’s capacity market.

But EPSA attacked ZECs from a different angle in its petitions.

“The question presented is whether the FPA pre-empts only state subsidies that explicitly require a wholesale generator to sell its output in FERC-approved auctions, or whether the FPA also pre-empts state subsidies that lack such an express requirement but that, by design, subsidize only generators that sell their entire output via such auctions, thereby achieving the same effect,” both petitions said.

“This is not a situation in which further percolation in the courts of appeals is warranted. Indeed, delay risks long-term distortion of the energy markets,” the petitioners said. “The programs already in place are causing multibillion-dollar distortions and skewing decisions about long-term investment in energy generation.”

In addition, the petition on the Illinois ruling said the 7th Circuit’s “decision also rests on an erroneous understanding of the structure and operation of the Illinois ZEC program,” and that while “these factual and procedural errors were addressed in a rehearing petition, the court took no corrective action.”

U.S. Supreme Court

Old Wine in New Bottles

Ari Peskoe, director of the Electricity Law Initiative at Harvard Law School, said, “These arguments about the text of the FPA and the court’s 2016 Hughes decision largely repeat the generators’ briefs filed at the 2nd and 7th Circuits. In rejecting these arguments, the 2nd Circuit panel found it ‘telling that [the generators] cannot persuasively explain why FERC’s holding [disclaiming jurisdiction over RECs] does not apply equally to ZECs.’”

Peskoe pointed out that amicus briefs filed at the appellate courts explain that “a decision endorsing petitioners’ sweeping view of FERC’s authority over all payments received by generators would threaten existing renewable energy programs and deny FERC the opportunity to harmonize its market regulation with state programs.”

The 7th Circuit’s opinion cited the Hughes ruling, in which the Supreme Court said it did not intend “to foreclose [states] from encouraging production of new or clean generation through measures ‘untethered to a generator’s wholesale market participation.’”

“And that’s what Illinois has done,” the 7th Circuit said. “To receive a credit, a firm must generate power, but how it sells that power is up to it. It can sell the power in an interstate auction but need not do so. It may choose instead to sell power through bilateral contracts with users (such as industrial plants) or local distribution companies that transmit the power to residences.”

EPSA had contended that Illinois’ ZEC program infringed on FERC’s jurisdiction by indirectly regulating interstate energy markets by using average auction prices as a component in a formula that affects the cost of the ZECs. But the 7th Circuit found the value of ZECs does not depend on the generators’ auction offers.

January 10, 2019

McNamee Declines to Commit to Resilience Docket Recusal

By Michael Brooks

FERC Commissioner Bernard McNamee on Monday informed Senate Democrats that ethics advisers told him he was not required to recuse himself from the commission’s ongoing inquiry into RTO/ISO grid resilience (AD18-7).

In a letter to Sen. Catherine Cortez Masto (D-Nev.) dated Jan. 7, McNamee attached a Jan. 2 memo to him written by Charles Beamon, FERC associate general counsel. In the memo, Beamon described his Dec. 12 meeting with McNamee, saying he advised the commissioner that he did “not view your prior position and statements as demonstrative of an unalterably closed mind as to” the proceeding.

Beamon, however, cautioned that “we must exercise continued oversight to ensure that Docket No. AD18-7 does not develop in such a way as to replicate or closely resemble” the Energy Department’s Notice of Proposed Rulemaking for FERC to order RTOs and ISOs to compensate the full operating costs of generators with 90 days of on-site fuel (RM18-1).

FERC Chief of Staff Anthony Pugliese, left, and Bernard McNamee, center, head of DOE’s Office of Policy, made the case for coal and nuclear price supports at a breakfast meeting of the Consumer Energy Alliance on the sidelines of the NARUC Annual Meeting in Baltimore in November 2017. Michael Whatley, right, CEA’s executive vice president, moderated. | © *RTO Insider*

McNamee helped draft the NOPR, unanimously rejected by FERC, as the department’s deputy general counsel for energy policy. In response to Democrats at his Senate Energy and Natural Resources Committee confirmation hearing in November, McNamee said he “clearly” would have to recuse himself from the NOPR docket, which Beamon reiterated in his memo. (See Democrats Urge McNamee’s Recusal from Resilience Docket.)

But Beamon said that although the dockets are related, “I advised you that I do not view the relationship as requiring your recusal.” He said he also emphasized the dockets were different proceedings and noted that the resilience docket “is an administrative inquiry in which the commission received over 200 comments suggesting various outcomes.”

After he was confirmed 50-49 in early December, 17 Senate Democrats wrote to McNamee on Dec. 12 — coincidentally the same day he met with Beamon — requesting he update them on what guidance he received. Along with his work on the NOPR, they also questioned his impartiality based on a leaked video of a speech he gave while working for the Texas Public Policy Forum in June. (See Senate Confirms McNamee to FERC.)

In the speech, McNamee criticized environmental groups and renewable energy resources, describing the efforts of his group to change public opinion on fossil fuels as a “constant battle between liberty and tyranny.”

Beamon’s memo quoted case law saying that parties cannot challenge the presumption of an agency official’s impartiality “by merely showing that an official has ‘taken a public position, or has expressed strong views, or holds an underlying philosophy with respect to an issue in dispute.’”

As an example, Beamon cited former Commissioner Philip Moeller’s comments in 2011 on a bill in New Jersey, which he said would “crater the capacity market” in PJM. The Maryland Public Service Commission had cited these comments in its request for rehearing of FERC’s acceptance of the RTO’s revisions to its minimum offer price rule (MOPR) (ER11-2875).

The court unanimously decided that Moeller’s comments “did not show that he ‘had made up his mind regarding two as-yet-to-be filed proceedings concerning a related, but very separate matter — the specific, regionwide operation of PJM’s MOPR,’” Beamon said.

Beamon concluded his memo by saying he “advised you to seek my guidance on any matter related to your past statements, positions, work or any other concerns that you may have.”

January 10, 2019

FERC OKs PJM Tx Constraint Penalty Factor Changes

By Robert Mullin

FERC on Tuesday approved PJM Tariff changes designed to bring the RTO into compliance with Order 844 by improving market participants’ insight into the use of transmission constraint penalty factors.

“The proposed revisions will provide transparency regarding PJM’s transmission constraint penalty factor procedures and also produce more transparent and appropriate pricing and investment signals that correspond to an underlying transmission constraint,” the commission said in its ruling (ER19-323).

Transmission constraint penalty factors are the values at which security-constrained economic dispatch (SCED) will relax the flow-based limit on a transmission line in order to relieve a constraint rather than redispatch a costly resource.

Issued last April, Order 844 said that a lack of transparency prevents market participants from understanding how the factors influence LMPs. (See FERC Orders RTOs to Shine Light on Uplift Data.)

In its compliance filing, PJM explained that its current logic for relaxing constraints prevents the penalty factor from setting the marginal value of a transmission constraint, thereby understating the severity of the constraint and producing LMPs that fail to send appropriate price signals to inform generation and transmission investment decisions.

FERC approved PJM’s proposal to remove the constraint relaxation logic from its market operations and allow the penalty factor to set the marginal value for a constraint when SCED “cannot produce a solution that manages the flow on a transmission constraint within the limits of the transmission constraint.”

The commission also found PJM’s Tariff revisions adequately describe how the penalty factor will be reflected in LMPs. The RTO had clarified that the marginal value for a constraint is used as an input for determining LMPs’ congestion component.

PJM also explained it will allow the penalty factor to set the marginal value for a constraint in market-to-market transactions, although it retains the ability to use the constraint relaxation logic at the request of an adjacent RTO.

“PJM states that it expects to use constraint relaxation logic for market-to-market congestion management with Midcontinent Independent System Operator Inc. until the second quarter of 2019, when MISO will update its market clearing engine to allow transmission constraint penalty factors to set the marginal value of the transmission constraint in its markets,” the commission noted.

PJM’s default transmission constraint penalty factor will be $2,000/MWh for real-time transactions within its own boundaries and $1,000/MWh for M2M coordinated transmission constraints on its side of a seam.

FERC also approved PJM’s plan to revise penalty factor values “to reflect persistent system operational or reliability needs, changes in the costs of resources available to relieve congestion, changes to operating practices for managing market-to-market coordinated constraints, and the unique attributes of certain transmission facilities.”

The commission additionally accepted the RTO’s proposal to post adjustments to penalty factor values “as soon as practicable” rather than setting a hard deadline, “in the event that an unforeseen circumstance arises that prevents modified values from being posted within such a deadline.” In doing so, it dismissed the Independent Market Monitor’s argument in favor of a deadline.

FERC also disagreed with the Monitor’s contentions that PJM should not retain the ability to apply its constraint relaxation logic for M2M constraints, as well as its assertion that penalty factor values take into account other system constraints, include RTO-wide reserve penalty factors.

“Establishing the default transmission constraint penalty factor values based on historical evidence, as PJM proposes, ensures that the SCED application considers all physically available dispatch options and available units to resolve binding transmission constraints,” the commission said.

The Tariff revisions take effect Feb. 1.

January 10, 2019

SPP Staff Outline Seams Strategy to SSC

By Tom Kleckner

SPP’s interregional relations staff on Wednesday shared with the Seams Steering Committee their strategic vision for seams efforts through 2021.

The vision is heavy on improving transmission planning across the seams and offering reliability coordination services in the Western Interconnection. Staff referred to the seams strategy as a “living, breathing document” that will eventually be posted on the committee’s website.

The goals include implementing improvements to the SPP-MISO Coordinated System Plan by the end of the first quarter, a process that will begin with a Jan. 31 meeting between RTO staffs and stakeholders.

SPP and MISO have revised their joint operating agreement’s planning criteria in the hopes of agreeing on a first interregional project between the two. Legal staff are currently drafting language for a MISO, SPP Tweak Interregional Criteria.)

The RTOs also plan to begin a new study this year, using the new criteria.

Other strategic goals include:

Implementing agreements between the SPP RC in the West and neighboring RCs;
Developing RC coordination agreements with neighboring western RCs;
Devising a cost-allocation Tariff mechanism for seams projects not driven by FERC Order 1000; and
Defining the coordination of grid-switchable resources with ERCOT during emergency conditions.

Clint Savoy, the RTO’s senior interregional coordinator, told the SSC that staff have begun reaching out to neighbors to evaluate the potential value and benefits of sharing operating reserve responsibilities with other balancing authorities.

The committee also welcomed ITC Holdings’ David Mindham and Corn Belt Power Cooperative’s Kevin Bornhoft as new members.

November M2M Payments Flow SPP’s Way

The MISO-SPP market-to-market (M2M) process resulted in more than $148,000 in SPP’s favor in November, the fourth straight month incurred payments have failed to reach $1 million.

Permanent flowgates accounted for the financial difference, binding for 53 hours. Temporary flowgates were binding for 592 hours but resulted in a $60.11 amount due to MISO.

SPP has amassed $51.8 million in distributions since the RTOs began the M2M process in March 2015, with payments flowing in its direction 21 of the last 26 months.

January 9, 2019

PG&E Stock Plunges, Credit Downgraded to ‘Junk’ Status

By Hudson Sangree

PG&E’s beleaguered stock price sank even lower Monday and Tuesday, dropping by more than 30% over two days because of fears the company could go bankrupt or be broken up by the state after two years of catastrophic wildfires in California. (See PG&E’s Troubles Mount After Camp Fire.)

The company’s share price fell from $24.40 late Friday to a new low of $16.79 as trading started Tuesday morning. It recovered slightly during the day Tuesday and closed at $17.56.

PG&E’s stock began its latest tumble after Reuters, citing unnamed sources, reported Friday the company was exploring filing for bankruptcy.

PG&E’s stock price plummeted after November’s Camp Fire and continued plunging this week amid talk of the company declaring bankruptcy and selling off its gas division. | *PG&E*

S&P Global Ratings dropped the company’s credit rating from investment grade (BBB-) to “junk” (B) status Tuesday and said it might make further downgrades if PG&E does not take clear steps to preserve its creditworthiness, given state officials may be unwilling to help the company.

“Previously, we assumed that given California’s robust renewable portfolio standards and the increasing risks of climate change, legislators and regulators would proactively work with the utility to preserve credit quality to achieve these goals. However, based on recent developments, we no longer believe this to be true given the utility’s own missteps,” S&P said. “We expect that negative public sentiment and the increased political pressure will challenge the regulators’ willingness and ability to implement measures to protect credit quality over the near term.”

Before the wine country fires of 2017, PG&E’s stock price had reached a high of more than $70/share. Just prior to the Camp Fire in November, it had been holding relatively steady for months. On Nov. 7, the day before the Camp Fire destroyed the town of Paradise, Calif., and killed 86 residents, the utility’s stock price stood at about $49/share.

The plunges after the 2017 and 2018 fires resulted in PG&E losing roughly $16 billion in market value over 14 months.

State fire investigators blamed PG&E equipment for starting 17 of the 21 major wine country fires in 2017 but have not determined the cause of the most destructive of those fires, the Tubbs Fire, which wiped out the northern portion of the city of Santa Rosa, Calif.

In recent court filings, PG&E reiterated its argument that a private landowner, who employed an unqualified person to run distribution lines on her property, may have started the Tubbs Fire.

The cause of the Camp Fire hasn’t been determined either, but PG&E reported severe damage to a 115-KV distribution line and flames near the origin of the Camp Fire on the morning it started. (See PG&E Grapples with Line Safety After Camp Fire.)

Also on Tuesday, PG&E reported Patrick M. Hogan, head of electric operations, would be retiring Jan. 28 and Michael A. Lewis had been elected by the board of directors to succeed him as senior vice president.

“Mr. Lewis, 56, has served as Vice President, Electric Distribution Operations of the Utility since August 2018,” PG&E said in a filing with the U.S. Securities and Exchange Commission. “At his previous company [Duke Energy], Mr. Lewis helped the distribution and transmission organizations achieve industry-leading safety benchmarks,” the utility said.

PG&E recently announced a “board refreshment” process in which it would seek to recruit more directors with safety experience, following criticism from the California Public Utilities Commission and lawmakers that its safety culture was deeply flawed.

January 9, 2019

Munis Wary of PJM Rules on Non-Retail BTM Generation

By Rich Heidorn Jr.

VALLEY FORGE, Pa. — A PJM proposal to revise the rules on non-retail behind-the-meter generation met with suspicion from municipal utilities and cooperatives at Tuesday’s Operating Committee meeting.

PJM introduced a proposed problem statement, saying current rules are inconsistent with Capacity Performance (CP) requirements and the lack of reserves for this growing class of resources could present reliability problems.

Non-retail BTM generation (NRBTMG) refers to resources used by municipal electric systems, electric cooperatives or electric distribution companies to serve load. They do not participate as supply resources in PJM markets but can be netted against their wholesale load to reduce transmission, capacity, ancillary services and administrative fee charges.

PJM’s rules on such resources resulted from a 2005 settlement agreement (EL05-127), before development of the RTO’s capacity market and CP constructs. NRBTMG resources can be called upon during the first 10 Maximum Generation Emergencies annually, while CP resources are required to perform during all Performance Assessment Intervals (PAIs). BTM operators that fail to perform face reduced netting benefits.

“The right to call upon NRBTMG during an emergency was established to address a concern that if too much generation is designated as NRBTMG and allowed to net against load, system reliability would be compromised since PJM would not be carrying reserves for a large amount of load associated with NRBTMG,” PJM said.

However, non-retail BTMG is not specifically addressed in PJM’s Emergency Procedures Manual (M-13), making it unclear whether such resources would be requested to operate during any emergency.

NRBTMG resources are expected to run at full output. “‘Full output’ was considered a reasonable expectation of performance at the time of the NRBTMG business rule development, when more traditional types of NRBTMG existed,” PJM said. “With the increased development of renewable NRBTMG in the PJM region, the expected performance level of NRBTMG should be reevaluated.”

PJM identified about 400 MW of non-retail BTMG in an outreach in 2006, before East Kentucky Power Cooperative, Duke Energy and American Transmission Systems Inc. (ATSI) joined the RTO, said PJM’s Theresa Esterly. The RTO hopes to get a current tally of such resources through current efforts to update its data on all distributed energy resources.

Closing ‘Loopholes’

Jim Benchek, FirstEnergy | © *RTO Insider*

Jim Benchek, of FirstEnergy, said his company will support the review, provided the scope of the issue is clarified, as a way to “cover up loopholes for avoiding performance requirements.”

“Calpine has been pushing to look at this issue for a while,” said Calpine’s David “Scarp” Scarpignato. While CP resources are penalized for failing to perform, the operators of underperforming NRBTMG will “lean on the rest of the system and they’re not going to face any kind of penalty,” he said.

Scarp also said the review is timely because any rule changes could affect the business models of DERs.

A Solution in Search of a Problem?

But representatives of cooperatives and municipal utilities questioned the need for new rules. “We want to be able to continue to use them the way we’ve been using them,” said Carl Johnson of the PJM Public Power Coalition.

Steve Lieberman, American Municipal Power | © *RTO Insider*

“You have a solution and you’re trying to find a problem,” said Steve Lieberman of American Municipal Power. “… It seems like you’re trying to make an equivalency between NRBTMG and capacity resources receiving capacity payments.”

Mike Cocco, of Old Dominion Electric Cooperative, agreed, saying ODEC would oppose extending CP rules to non-capacity resources. He said any PJM proposal affecting NRBTMG must be comparable to the netting rules for retail BTMG. Cocco suggested expanding the scope of the problem statement to include a review of existing netting rules for both NRBTMG and retail BTMG.

Scarp also suggested the inquiry be broadened to include retail BTMG, saying performance failures by such resources “could give you the same reliability issues.”

Lieberman said expanding the scope could make it impossible to complete the work in the 10-month time frame proposed by PJM. “I don’t want to face another letter from the Board [of Managers]” setting a deadline for action, he said, referring to the Board’s recent ultimatum on market formation changes. (See Section 206 Filing on PJM Reserve Pricing Likely.)

Operating Committee Chair Dave Souder asked stakeholders to propose any changes to the problem statement before the OC’s next meeting, when the RTO hopes to bring the inquiry to a vote.

January 9, 2019

FERC Discloses Data Behind New England ROE Order

By Michael Kuser

FERC on Monday disclosed data underlying its new formula for setting return on equity rates for New England transmission owners (NETOs) and explained how the data influenced the ROE methodology outlined in an October 2018 briefing order.

But the commission’s Jan. 7 order also noted it had not yet made any final determinations and referred complainants to the paper hearing on the issue (EL11-66-001, et al.).

The release of information came in response to a Nov. 16 motion for expedited disclosure by a coalition consisting of Connecticut’s utility regulator and New England power cooperatives. The group sought the data and analyses underlying two graphs the commission referenced in its decision to no longer rely solely on the discounted cash flow (DCF) model but give equal weight to results from the DCF and three other techniques: the capital asset pricing model (CAPM), expected earnings model and risk premium model. (See FERC Changing ROE Rules; Higher Rates Likely.)

The Connecticut Public Utilities Regulatory Authority, Eastern Massachusetts Consumer Owned Systems, Massachusetts Municipal Wholesale Electric Company and New Hampshire Electric Cooperative asked the commission to “identify and, where not already in the record in these four proceedings, release the sources, data sets, and analyses underlying Figure 2 and Figure 3 in its October 16 Order.”

The commission’s new policy came in its long-awaited response to the D.C. Circuit Court of Appeals’ April 2017 ruling vacating FERC’s 2014 order on the NETOs’ ROE rates. (See Court Rejects FERC ROE Order for New England.)

Data Details

The Monday order said that Figure 2, “ROE Results from ROE Models,” shows the ROE results from the four models over the four test periods at issue in the proceeding and that in calculating the expected earnings midpoint for Period 2, it had excluded ITC Holdings and Wisconsin Energy from the proxy group “as high-end outliers because their ROEs were more than 150% of the proxy group median for the NETOs,” which was 10.225%.

FERC’s new ROE formula gives equal weight to four models. | *FERC*

ITC Holdings was similarly excluded from the proxy group for Period 3, as was CenterPoint Energy for Period 4. The commission listed all other data effects as “none,” except for its CAPM ROE midpoint, which had been rounded up in Figure 2 to 10.46% from 10.45%, as its exact midpoint is 10.455%.

The motion for disclosure said, “Figure 3, which is titled ‘Regulated Utilities PE Chart’, appears to be excerpted from a report generated by Evercore ISI, an investment banking advisory firm. This report is not in the record for these proceedings and appears from our research to be proprietary and not publicly available.”

The commission responded that Evercore ISI produced Figure 3 and that it “does not have access to the data or analyses that were used to produce that chart and therefore cannot provide that information. The Briefing Order relied on Figure 3 only for the limited purpose of showing that there had been a substantial increase in utilities’ price to earnings ratio during the period [of] October 2012 to December 2017.”

Regulated utilities price/earnings | *Evercore*

Figure 3 was part of the briefing order’s explanation of why, during that period, “utility stock prices appeared to have performed in a manner inconsistent with the underlying premise of the DCF model that an investment in common stock is worth the value of the infinite stream of dividends discounted at a market rate commensurate with the investment’s risk,” said the commission.

Moreover, the commission said it did not rely on Figure 3 for any final determination on the use of the DCF model to determine utility ROEs.

January 8, 2019

Cancel Transource Line, Md. Panel Says

By Rich Heidorn Jr.

Maryland officials have recommended the state’s Public Service Commission reject Transource Energy’s controversial Independence Energy Connection, saying the company and PJM failed to examine alternative solutions, as required by state law.

The Power Plant Research Program (PPRP) of the Maryland Department of Natural Resources asked the PSC on Dec. 20 to dismiss Transource’s application for a certificate of public convenience and necessity (CPCN) or put the filing on hold until the company and PJM review proposals to add capacity to existing transmission lines in the eastern segment of the project in Harford County (Case 9471).

The $372 million project would add two 230-kV double-circuit lines totaling about 42 miles across the Maryland-Pennsylvania border: a western line between the Ringgold substation in Washington County, Md., and a new Rice substation in Franklin County, Pa.; and an eastern line between the Conastone substation in Harford County, Md., and a new Furnace Run substation in York County, Pa. It would be PJM’s largest-ever market efficiency project.

Once referred to as the AP South Congestion Improvement Project, Transource’s Independence Energy Connection project would consist of two lines. The western portion would run from the Ringgold substation in Maryland to the Rice substation in Pennsylvania. The eastern line would run from the Conastone station in Maryland to the Furnace Run station in Pennsylvania. | *Transource*

The PPRP said Transource had failed to meet state law requiring the examination of alternatives if an existing transmission line “is convenient to the service area; or the use of the transmission line will best promote economic and efficient service to the public.”

“After substantial discovery,” the PPRP said, “it is clear that there was no examination to consider an existing transmission line as an alternative for the eastern segment of the project … prior to filing the CPCN for the project, even though the existing transmission lines appear likely to be both convenient to the service area and to best promote economic and efficient service to the public.”

The agency said the need for the eastern segment of the project could be met by the existing Furnace Run-Conastone and Furnace Run-Graceton 230-kV double-circuit transmission tower lines, which each have only one 230-kV circuit and could carry a second.

“Transource’s application did not identify, nor consider, these nearby existing tower lines as an alternative to the project,” the PPRP said.

The PPRP said it provided a “conceptual alternative” using the spare tower capacity, but Transource rejected it after initial modeling by PJM identified two single-contingency thermal criteria violations. The PPRP said the violations don’t eliminate the nearby lines as a viable alternative.

“It is not uncommon for PJM to identify thermal violations in its transmission planning process and then to seek out solutions. In fact, on the west segment of this project, transmission system enhancement projects were necessary to allow the IEC-West project to connect into Maryland,” the agency said. “With regard to the IEC-East project, there are other transmission line configurations using these existing tower lines that very well may not produce reliability concerns while providing regional benefits in a manner that minimizes the environmental and socioeconomic impacts to the state.”

The PPRP said PJM and Transource also rejected two other conceptual alternatives as “going beyond considering the use of existing transmission corridors [and representing] significant material changes to the electrical configuration of the project.”

“Alternatives utilizing the existing tower lines have not yet been examined in a manner that will allow the commission to complete its review under [state law]. Transource and PJM’s apparent unwillingness to investigate these existing tower lines leaves unresolved whether there is a viable and preferred alternative to the IEC-East project.”

Transource Response

In a response Monday, Transource insisted its application is complete and that it has made a prima facie case that the project is needed and “will provide enormous economic benefits to Maryland customers.”

“The application includes substantial evidence for the commission to carry out its obligation … including the consideration of existing transmission lines,” Transource said. “A dispute over the consideration, or lack of consideration, of any one hypothetical alternative, with no evidence whatsoever regarding its feasibility, among an infinite universe of similar ‘alternatives’ is not the proper subject of a motion to dismiss.”

The company said state law does not require applicants to conduct engineering analyses of every possible alternative. “Rather, disputes over whether the commission should consider an alternative are properly the subject of competing testimony at the evidentiary hearing.”

Reliability Value?

The state officials also said the commission should reject Transource’s attempt to justify the project — approved by PJM in 2016 to relieve transmission congestion — on reliability grounds.

PJM said in a November white paper re-evaluating the project that it would reduce load costs by $707.3 million in net present value over 15 years, producing a benefit-cost ratio of 1.4, exceeding the minimum 1.25 ratio required for inclusion in the Regional Transmission Expansion Plan. (See PJM Reiterates Support for Embattled Transource Project.)

It also “resolves burgeoning reliability issues,” PJM said. Although the project was not needed to address reliability violations when it was approved, the RTO said, it noted “that the project would inherently enhance system reliability by introducing additional transmission network paths.”

“In parallel with the September 2018 benefit-cost ratio re-evaluation, PJM assessed the extent to which the Transource project provides identifiable reliability benefits. Power flow results have confirmed that the Transource project does indeed solve identified 2023 overloads on a 500-kV line, a 500/230-kV transformer and other transmission facilities,” the RTO said.

The PPRP suggested PJM’s shift was a bait and switch. “If PJM has now determined that there are reliability concerns and an associated need for transmission system enhancements, it would be more appropriate to first investigate reasonable alternatives within the relevant PJM processes rather than latching solutions on to this discretionary market efficiency project,” it said.

Transource denied it was changing its position on the reason for the project. “The additional analysis provided by PJM was routine and anticipated, and the results of the analysis only add to need for the project, they do not substitute the purpose for the project.”

A group of residents who live in or near the proposed path supported the PPRP’s motion to dismiss. STOP Transource Power Lines MD said the line would disrupt existing farm and agricultural operations and damage land under permanent preservation easements.

“The failure on the part of the applicant and, to a lesser degree, PJM to consider alternative routes is particularly galling considering the substantial sums expended by the members of STOP Transource in the instant matter to date, which will increase significantly if this matter proceeds to a hearing,” the group said. “If, in fact, the existing towers can accommodate the lEC-East project, thus avoiding its devastating impacts to the members of STOP Transource and other individual property owners, they must be seriously considered.”

Pennsylvania Proceeding

Pennsylvania regulators will be receiving written testimony on Transource’s siting request until Feb. 11, with evidentiary hearings set for Feb. 21-22 and Feb. 25 to March 1 (A-2017-2640195).

January 8, 2019

Rice Study on Renewables’ Potential Has its Believers

By Tom Kleckner

A recent Rice University study that suggests Texas renewable power production could become more reliable by combining different resources and locations did not surprise independent developer Mannti Cummins.

He’s been there and done that, having helped bring the Peñascal Wind Farm project in South Texas online in 2010. The 404-MW facility also happens to be one of the sites used in the Rice study.

“This kind of confirms the rustic logic of common-sense folks who don’t have the ability to do the necessary calculations and analytics,” Cummins said from Mexico, where he is working on another project in Baja California Sur. (See Energy Wildcatter Hopes to Make His Mark in Emerging Mexican Market.)

“This kind of confirms, with an academic methodology, what we’ve all thought is going to be the future,” he said.

In their study, Renewables: Wind, Water, and Solar, Rice researchers Dan Cohan and Joanna Slusarewicz analyzed data from five wind and seven solar sites across West and South Texas. Because of the state’s varying wind patterns and solar irradiance, they found that pairing solar power with either West Texas winds or South Texas winds will increase renewable power production.

West Texas winds peak during early night hours (6-10 p.m.), while South Texas winds tend to follow load patterns and peak in the late afternoon. The researchers said that pairing solar with western wind farms provides the highest levels of firm capacity with an 87.5% threshold, increasing reliable power production on an annual basis.

South Texas’ late-afternoon wind peaks suggest that combining solar with wind “might increase reliable power production over the course of a summer day during hours of high demand,” they wrote.

Cummins said the Peñascal development team in the early 2000s chose the barren scrub of South Texas because the wind peaks at the right time. “It’s just perfect with the load profile,” he said.

The Peñascal site is also situated between the Corpus Christi and Rio Grande Valley population centers, where it could take advantage of under-used transmission facilities without taking part in the state’s Competitive Renewable Energy Zones process. (The wind farm did benefit from more than $220 million in federal stimulus funds.)

“But nobody ever thought about pairing [wind] with solar,” Cummins said. “You can start talking about it because [solar is] economical.”

He said that prices for installed solar are 50% below where they were three years ago, dropping from $2,000/kW to $900/kW. Solar is crushing natural gas, Cummins said, a situation he expects to continue as battery storage becomes more commonplace.

“As the price of battery storage drops like a rock, that’s the future,” he said.

Cummins is following that concept of wind-integrated solar energy with his Coromuel project at the tip of the Baja California peninsula. The 50-MW wind facility, named for the local weather phenomenon, will include 600-kV solar panels at the foot of each turbine.

“When the wind has its own name, it’s probably consistent enough for wind generation,” he said, comparing the afternoon peak to South Texas winds.

“The rise of clean energy appears to be everywhere across Texas,” said developer John Billingsley in a statement following the Rice study’s release. Billingsley is CEO of Global Energy and also launched Sunfinity Renewable Energy three years ago.

Billingsley agrees with Rice’s Cohan, who said the research shows “nowhere else in the world [is] better positioned to operate without coal than Texas is.”

As it is, coal only accounts for 15.5 GW of ERCOT’s existing resources, with wind and solar combining to account for 22 GW. No coal projects are listed in the ISO’s latest generator interconnection report, while there are 14.3 GW of wind, 4.3 GW of solar and 2.7 GW of gas projects with signed interconnection agreements.

During a recent appearance in Houston, ERCOT CEO Bill Magness said, “It’s all gas, wind and solar. There are no other resources coming along.”

ERCOT expects to have as much as 5 GW of solar energy on the system by 2021, much of it in West Texas.

“We’ve only begun to scratch the surface in terms of truly harnessing our clean, renewable resources,” Billingsley said. “The next several years will see amazing strides forward.”