Page 1671 – RTO Insider

March 8, 2016

FERC Eliminates Intertie Convergence Bids in CAISO

By Robert Mullin

FERC last week approved a request by CAISO to eliminate from its Tariff a long-suspended provision establishing convergence bidding at scheduling points on the interties into California.

The commission’s order eliminated the prospect that CAISO would reinstate a market mechanism it revoked within months of implementing it in 2011 (ER15-1451-001). At the time, the ISO’s Market Monitor determined that bidding strategies at the interties underpinned a complex scheme to manipulate prices and inflate payouts in other areas of the California market.

CAISO has in recent years explored reviving the mechanism in light of structural changes in Western markets, but it ultimately sought a full repeal based on concerns that illiquidity in 15-minute trading left intertie points vulnerable to gaming.

FERC’s ruling did not affect convergence bidding at points inside the ISO balancing area. At the request of municipal utilities in Anaheim, Azusa, Banning, Colton, Pasadena and Riverside, FERC also directed CAISO to delete from its Tariff an additional reference to virtual bidding in order to avoid ambiguity.

Convergence — or virtual — bidding allows market participants to hedge their physical positions and limit exposure to day-ahead and real-time price differentials. A convergence bid is a purely financial bid implying no obligation to take or deliver electricity. Instead, a market participant buys or sells “virtual” energy in the day-ahead market, a position required to be automatically liquidated in the opposite direction in real time.

Depending on the relative movements in the two markets, the participant either pockets or pays the difference between the two prices. Bidders are not required to control physical resources or serve loads in the ISO, allowing speculators to take positions in the market.

RTOs have adopted convergence bidding under the theory that the practice narrows the gap between day-ahead and real-time prices as traders arbitrage spreads between the two markets. The benefit is a more predictable spot market, protecting utilities from price swings stemming from load fluctuations and unplanned generating outages.

Troubled from the Start

In California, convergence bidding was fraught with problems since CAISO introduced the practice two years after restoring its day-ahead market. A week after implementing the market in February 2011, CAISO suspended bidding at nodes on nine interties linked to the Mountain States region because of a software glitch that risked overscheduling those points in the physical day-ahead market.

That incident was followed months later by the more serious discovery that some CAISO market participants were using virtual supply bids on the interties to offset virtual demand bids at nodes located just inside the state, a gaming strategy that produced no benefit for the physical market and cost the ISO more than $50 million.

(Virtual trades at CAISO’s New Melones intertie are at the center of market manipulation allegations filed by FERC in December. The defendant last week asked FERC to compel CAISO to disclose information about market design flaws (IN16-2). See earlier story, FERC Seeks $2.5M Fine in CAISO Market Manipulation.)

The strategy was facilitated by predictable differences in prices stemming from what the ISO referred to as a “bifurcated” settlement process, with the interties settled at the hour-ahead price and internal points in real time. Shortly after identifying the issue, CAISO suspended bidding at the interties indefinitely — or at least until it could resolve the bifurcation issue.

Liquidity Concerns

That goal would ultimately elude CAISO. While FERC Order 764 — which mandated 15-minute scheduling between neighboring balancing areas — should have helped, the ISO became concerned about declining short-term trading volumes at the interties, which could reintroduce opportunities for strategic bidding. A 2015 report from the ISO’s Market Monitor indicated that “most of the dozens of CAISO interties have no market participants providing economic bids in the 15-minute market and only a few interties have multiple market participants providing such bids.”

CAISO hoped Bonneville Power Administration’s implementation of 15-minute scheduling — synching it with CAISO’s schedule — would boost exports from the Pacific Northwest. But the change had little impact on trading activity.

“The CAISO does not yet understand the causes of this low market liquidity,” the grid operator wrote in an April 2015 filing asking FERC to extend the suspension of convergence bidding on the interties. “Based on informal feedback from market participants, the CAISO believes that some of the possible causes may be neighboring balancing areas not supporting 15-minute schedule changes, difficulty in procuring transmission in 15-minute blocks, an absence of bilateral trading at a 15-minute granularity and reticence of resource owners to adjust their output within the hour.”

According to a report by CAISO’s Department of Market Monitoring (DMM), low 15-minute liquidity could translate into a situation in which convergence bids would first settle at a day-ahead market price that includes intertie congestion, then be liquidated at a 15-minute market price not subject to congestion because of light physical volumes. That would give bidders incentive to profit from the structural differences between congestion prices in the day-ahead market and the 15-minute market.

“Regardless of the causes,” CAISO wrote in its April 2015 filing, “based on DMM’s recent analysis, the CAISO has determined that the existence of such low market liquidity, as evidenced by the lack of economic bids submitted in the 15-minute market, makes it problematic to reinstate intertie virtual bidding.”

March 8, 2016

ERCOT: Ample Capacity to Meet Spring, Summer Peaks

By Tom Kleckner

ERCOT said last week it continues to expect to have sufficient resources to meet projected peak-demand during the spring and summer, with more than 79,000 MW of generation capacity available.

The Texas grid operator is projecting a spring demand peak of 58,279 MW, a 700-MW increase from last November’s preliminary spring assessment, said Pete Warnken, ERCOT’s manager of resource adequacy, during a March 1 conference call. The revised peak is based on weather conditions from May 2006; the previous estimate used average weather conditions from 2002 to 2014.

Warnken said staff took into account multiple scenarios under a variety of conditions in issuing its Seasonal Assessment of Resource Adequacy (SARA) for this spring. The report includes a new scenario based on low wind power output during peak hours.

ERCOT estimates that even with 9,482 MW of maintenance and forced outages in May, it will still have 11,598 MW of capacity available for operating reserves, well above the 2,300 MW considered acceptable.

The spring forecast is based on expected weather conditions similar to those that occurred in May 2006 and typical seasonal generation outages, based on historical performance. ERCOT expects the spring peak to occur in late May, following completion of most seasonal plant maintenance to prepare for summer’s heat.

“The month of May shows potential for above-normal temperatures, which could lead to an early taste of summer,” said ERCOT meteorologist Chris Coleman.

The grid operator’s latest SARA includes more than 200 MW of installed solar capacity. ERCOT estimates solar resource availability at a 58% capacity factor — or 171 MW — based on its typical performance during peak spring conditions.

ERCOT’s preliminary summer SARA projects a summer peak of 70,588 MW, its first peak above 70,000. The current record is 69,877 MW, set last August.

ERCOT estimates it will have more than 79,000 MW of available generation this summer, including an additional 731 MW of fossil, nuclear and biomass generation from the preliminary spring SARA, 1,068 MW of new gas-fired generation and 723 MW of additional wind energy.

The final summer SARA is scheduled to be released in May.

March 8, 2016

NV Energy has Smooth EIM Integration, CAISO Says

By Robert Mullin

NV Energy had a smooth integration into the Western Energy Imbalance Market, CAISO said Monday in its fourth-quarter market report.

Department of Market Monitoring (DMM) manager Keith Collins noted that after NV Energy joined the EIM on Dec. 1, Nevada imbalance prices quickly converged with those in CAISO’s broader system, a development that has so far continued into this year. That stood in contrast with the price swings that still beset PacifiCorp’s balancing area, stemming from physical constraints on the system.

“One of the things we noted with the [NV Energy] launch was that the variability [of prices] within the Nevada area was fairly limited,” Collins said.

CAISO attributed NV Energy’s easy adjustment to the high amount of transfer capability between Nevada and California. Limited congestion translates into a freer flow of both imbalance energy and capacity between the balancing areas, avoiding the need to relax CAISO’s flexible ramping constraints in load pockets poorly served by flexible capacity. Relaxation of the constraints ultimately drives up real-time energy prices by forcing relatively fast, efficient units out of the 15-minute energy market queue and into the obligatory market for ramping capacity.

By comparison, flexible capacity issues continue to weigh the EIM’s PacifiCorp East area, with the ramping constraint being relaxed in more than 10% of intervals over the quarter, frequently boosting real-time prices by the maximum $60/MWh adder associated with capacity procurement shortfalls. CAISO did note, however, that relaxations in PacifiCorp East declined during December, reversing the uptrend seen in the previous quarter. While generating units returning from outages likely helped relieve constraints, the DMM suggested that NV Energy’s entry into the EIM might be providing longer-term structural benefits for PacifiCorp.

“The market is more of a regional market with the inclusion of NV Energy because of the increased transfer capacity,” said Collins. “It’s more of a single market.”

Bid Cost Recovery Payments Down

Collins pointed to the decline in bid cost recovery (BCR) payments as the second biggest “theme” of the fourth quarter. CAISO payouts came to $25 million under the market mechanism, compared with $31 million in the third quarter and $25 million during the same period in 2014. BCR payments attributed to residual unit commitments (RUC) fell from $10 million to $3 million quarter over quarter because of decreased payouts to “long-start” units.

“This is a big shift, although virtual supply has played a role,” Collins said.

The DMM report describes the link between the virtual — or convergence — bidding market and bid cost recovery payment volumes, explaining that lower virtual supply volumes in the fourth quarter “primarily” caused the RUC process to commit fewer resources compared with the prior period. The report notes that RUC procurement “appears” to be driven by the need to replace cleared virtual supply bids, which offset physical supply in the day-ahead market.

“Part of that is that renewables tend to be under-scheduled,” Collins said. “Virtual schedules are counterbalancing that.”

The report also showed that real-time commitments accounted for $12 million in BCR payments, in line with historical norms, while day-ahead payments were lower than any fourth quarter since 2011.

Additional highlights from the Market Monitor’s report:

Day-ahead and 15-minute prices declined to the lowest level of the year, with day-ahead peak averaging $33/MWh. December saw both markets fall to their 15-month lows. Collins noted that both loads and natural gas prices continued to trend lower, with the latter hitting 15-year lows.
Price spikes increased in the five- and 15-minute markets but remained “relatively infrequent.” October saw an “unusually high” number of intervals in which prices surged to more than $1,000/MWh because of low day-ahead scheduled load and regional congestion.
Congestion in the ISO was relatively low and had little impact on prices.
The volume of dispatchable import bids in the 15-minute market increased by 19% compared with the third quarter, while export bids jumped 20%. Most 15-minute import-export activity was submitted by small number of entities on three interties — Malin, Palo Verde and Rancho Seco.

March 7, 2016

UPDATED: Exelon, Pepco Urge Compromise Deal to Win DC PSC OK for Merger

By Suzanne Herel and Rich Heidorn Jr.

Exelon on Monday offered a split D.C. Public Service Commission a “middle ground proposal” in a bid to salvage its acquisition of Pepco Holdings Inc.

In a joint filing, the companies asked the commission to approve either the original settlement negotiated with Mayor Muriel Bowser or the revised proposal outlined by Commissioner Joanne Doddy Fort and supported by Commissioner Willie Phillips on Feb. 26. Commission Chairwoman Betty Ann Kane opposed the revised settlement after voting 2-1 with Fort to reject Bowser’s deal. (See DC PSC: Will OK Exelon-Pepco Deal for Additional Concessions.)

The companies also offered a third alternative: adopting Fort’s revised settlement, while addressing the mayor’s concerns with shielding residential customers from rate hikes. It would give the PSC discretion to use an additional $20 million — which Bowser’s settlement earmarked for smart grid and environmental programs — for rate relief.

The companies did not offer to increase the $72.8 million customer investment fund (CIF) they are offering D.C. to approve the merger.

The deal began to look doubtful last Tuesday as Bowser, the Office of the People’s Counsel and Attorney General Karl Racine announced their opposition to revised terms set out by Fort. D.C. Water followed with its rejection later in the week. (See Exelon-Pepco Deal in Doubt as Mayor, Consumer Advocate Balk at New Terms.)

Together they represent three of nine settling parties that must agree to the new deal in order for it to be approved without further commission action. At issue for all was the reallocation of $25.6 million from the CIF that would have shielded residential consumers from rate hikes until 2019. The PSC voted 2-1 to defer a decision on how to spend the funds until the next Pepco rate case, signaling that it would distribute the money to nonresidential customers as well.

The commission’s Feb. 26 order had required responses from the settling parties by March 11. Exelon and Pepco asked the PSC to rule on their new proposal no later than April 7.

“The joint applicants believe that the commission can address its concerns with the residential customer base rate credit, as well as the settling parties’ concerns with the terms of the [revised settlement], through additional alternative terms which preserve the function of the residential customer base credit and move $20 million in CIF monies from the newly created [Modernizing the Energy Delivery System for Increased Sustainability] pilot project subaccount to a separate customer base rate credit fund.”

The $20 million fund would be spent following Pepco’s next base rate case as directed by the commission, potentially providing commercial customers rate relief or increasing funding for the Low-Income Energy Assistance Program.

“In the event that the commission determines that any or all of the additional $20 million should not be used for these purposes, it could allocate any unused portion of the $20 million to the MEDSIS pilot project subaccount.”

The companies said their proposal “does not prevent the commission from using CIF monies to advance the grid modernization proceedings in [a second docket,] Formal Case No. 1130. Instead, the revised allocation provides the commission with additional discretion over how best to use $20 million of the $72.8 million CIF to advance its competing priorities.

District of Columbia Public Service Commission (DC PSC) — D.C. Councilwoman Mary Cheh (at podium) is joined by other councilmembers and candidates at press conference opposing merger Wednesday.

“It would be tragic if customers lost the $72.8 million CIF and the many other benefits of the merger recognized by the commission and the settling parties because of disputes over how a portion of the CIF should be allocated,” they wrote.

The mayor, OPC and attorney general had no immediate comment on the companies’ revised proposal.

The Power DC coalition immediately asked the PSC to reject it.

“Exelon’s latest filing is another example of the company’s total arrogance and disregard for D.C. residents,” said spokeswoman Anya Schoolman. “The Public Service Commission shouldn’t let Exelon rearrange deck chairs on the Titanic. It is time for D.C. to move on.”

Councilwoman Mary Cheh also signaled her opposition. “We expected that Exelon would try a Hail Mary pass, but from my analysis it doesn’t appear to satisfy requirements set forth by the Office of the People’s Counsel in terms of protections for ratepayers,” she said.

Exelon not Giving Up

CEO Christopher Crane said in a Feb. 3 earnings call that the company would abandon the merger and begin buying back the 57.5 million shares it issued for the $6.8 billion deal if D.C. regulators did not approve it by March 4.

But company officials said Thursday they were delaying the deadline as a result of the PSC’s action Feb. 26.

“March 4 was the date after which Exelon and Pepco Holdings would have the right to stop pursuing the merger, if the Public Service Commission had not acted by then,” Exelon said in a statement. “Because the commission issued its order on Feb. 26, the March 4 date is no longer a trigger, and we are free to stop pursuing the merger if either party so chooses.”

Political Posturing?

Guggenheim Securities analyst Shahriar Pourreza said the fate of the merger may depend on whether Bowser and other officials truly want out of the deal or are playing politics.

“The big swing factor is if the mayor, attorney general and Office of [the] People’s Counsel are politically posturing or if they used Friday as an excuse to get out of this deal,” he told RTO Insider. “If it’s the former, it’s probably workable.” But, he said, “the longer they wait, the more the fundamentals of Pepco deteriorate and … the less attractive this transaction is.”

The PSC said that if all settling parties agree to its offer, the merger will be approved without further commission action. None of the D.C. officials opposing the PSC settlement has proposed a counteroffer.

The acquisition would give Exelon Pepco’s stable regulated income and the crown as the nation’s largest utility. But Pourreza said the deal has “materially deteriorated” over time. In a research note earlier in the week, he said, “We believe there is increasing likelihood Exelon could walk from the deal.”

Pepco ‘in Distress’?

“You kind of wonder if this even makes sense for Exelon,” he said. “There are plenty of single-state regulated utilities that they can go acquire that are not in as much financial distress as Pepco. This is not a healthy utility as a standalone entity.”

The PSC disagrees.

“There is no evidence in the record that Pepco could not continue to perform, and perform adequately and reliably as required by law, absent the … approval of Pepco’s sale to Exelon,” it said in its order Feb. 26. “Indeed, as the commission found in [its August 2015 order in the case], ‘PHI is financially healthy as a standalone company and would continue to be so if the merger is not consummated.’”

The merger already has the blessing of FERC and regulators in Delaware, Maryland, New Jersey and Virginia. They signed on under a “most favored nation” status, meaning in the end, all will be compensated equivalently — a disincentive for Exelon to sweeten the deal further with the district, Pourreza said.

If the merger doesn’t go through, Pourreza said, other suitors might be deterred from trying to purchase Pepco, given the regulatory hurdles D.C. has presented. “I think that these regulators have jeopardized this utility,” he said.

Dividend in Doubt?

On Monday afternoon, Pepco’s stock closed at $24.22, down 20 cents (0.82%) for the day. Exelon’s shares closed at $33.92, up 56 cents (1.68%).

If the merger doesn’t close, Pepco shares could lose $4 to $5 per share, Pourreza wrote. “Given that [Pepco] has been out of a rate case since 2014 and the delays with this merger, [it] has materially deteriorated as a standalone company, in our view.”

That could push its $1.08/share dividend to a 6% yield.

“It’s even questionable if they can support the dividend,” he said. “It’s pretty mind-boggling, the games that these regulators are playing. The agreement that the commission brought on Friday is very workable. I sort of question whether the commission did this because they knew that the settling parties wouldn’t go for this.”

Pourreza said he was at a loss to speculate what more Exelon could offer to salvage the deal, noting that “in a perfect world,” it should be offering less, not more, for Pepco at this point.

“I thought what the commissioners put out was equitable and now all of a sudden this is coming down to the $27 million issue,” he said. “It doesn’t make any sense to me. I tend to think [Bowser, Racine and OPC Sandra Mattavous-Frye] want out of this deal. … This is very abnormal.”

Cheh said the difference between using the fund to insulate ratepayers temporarily, only to have Exelon recoup the difference after four years, and disbursing the money when there is an actual rate case is not dramatic.

That, she said, leads her to think that Mattavous-Frye — an initial opponent of the merger who reversed course to back the mayor’s settlement — used the PSC’s proposed changes as an excuse to back away from the deal.

“Once Mattavous-Frye was out, the mayor was kind of stuck, I kind of think, because what was she going to say, ‘I think it was a good deal?’” Cheh said.

“What was at issue was a power struggle between the PSC and the mayor and who trusts whom,” Cheh said. “The fact that it may be scuttled over who gets to play with this money seems another surprising turn in all of this.”

One sticking point is that the rate relief would be shared with commercial customers, Cheh said. The U.S. General Services Administration, representing the federal government, the largest electricity consumer in the district, opposed the merger until the PSC offered the concession to broaden rate relief.

The settlement would have protected residential ratepayers through Bowser’s four-year term and potential reelection campaign.

“People have been saying all kinds of things,” Cheh said when asked if that might be a factor in Bowser’s insistence on preserving the rate credit. “Now that my rate increase may come right in the middle of your term — if you were the mayor, that’s something you would take into account.”

March 4, 2016

FERC OKs Revision to NYISO DR Pricing

By William Opalka

FERC on Tuesday approved changes to NYISO’s scarcity pricing logic that the ISO says will better reflect the real-time value of demand response (ER16-425).

NYISO implemented its current, ex-post scarcity pricing logic in 2013. The new logic allows the ISO to incorporate scarcity pricing into its real-time optimization. (See NYISO Seeks OK for New Scarcity Pricing Rules.)

“NYISO’s proposal increases price transparency by ensuring consistency between resource schedules and pricing outcomes in real-time when NYISO activates [demand response] resources, thereby reducing the potential for uplift costs,” the commission said.

“NYISO’s proposal recognizes that capacity that is available within 30 to 60 minutes can be dispatched to meet load prior to activating [demand response] resources. Thus, NYISO will procure a greater amount of available operating capacity from the market before relying on [demand response] resources and triggering scarcity pricing than under its existing rules,” FERC added.

As a result of the new logic, the ISO will:

Increase the value of Southeastern New York 30-minute reserves from $25/MW to $500/MW at all times to align the value of reserves with the actual cost of providing them;
Increase in the value of the middle pricing point of the regulation service demand curve (shortages of regulation service greater than 25 MW but less than 80 MW) from $400/MW to $525/MW at all times;
Reduce the target level for Southeastern New York 30-minute reserves to zero during actual or anticipated severe weather conditions (“storm watch events”); and
Increase the New York control area 30-minute reserve demand curve values priced at less than $500/MW to $500/MW, effective in real time during any DR activation.

The changes were supported by the Electric Power Supply Association, the Independent Power Producers of New York and the New York Transmission Owners.

The commission rejected protests by the New York Department of State’s Utility Intervention Unit, saying its concern that NYISO’s filing missed an opportunity to remedy an alleged flaw in its existing scarcity pricing mechanism was beyond the scope of the case.

FERC also rejected the UIU’s argument that the proposal could result in less efficient dispatch of generating resources and higher production costs. “We find that the benefits of increasing price transparency and incorporating scarcity pricing in the real-time market software outweigh such concerns,” the commission said, adding that “additional system changes may be required to further optimize the scarcity pricing mechanism and avoid the potential issues” the UIU raised.

FERC ordered the ISO to submit a compliance filing clarifying tariff provisions differentiating between scarcity events, when it calls on DR, and shortage events, when the market is short of operating, regulation, or transmission reserves.

The changes will become effective once NYISO deploys the required software changes. The ISO expects to complete the work by June 30.

March 1, 2016

Witnesses Ask CFTC to Drop ‘Private Rights’ Clause

By Rich Heidorn Jr.

WASHINGTON — A parade of witnesses implored the U.S. Commodity Futures Trading Commission Thursday to reverse its position in a case that they say could undermine the broad exemptions the commission granted RTOs and ISOs in 2013.

At issue is the CFTC’s draft order on a request from SPP seeking the same exemptions from the Commodity Exchange Act (CEA) that the commission granted the six other RTOs and ISOs.

The CFTC’s 2013 order exempted electricity transactions subject to FERC-approved tariffs from most provisions of the CEA while retaining its general anti-fraud and anti-manipulation authority.

SPP was the only grid operator not party to the 2013 order because its day-ahead market was not fully implemented until March 2014. Unlike the 2013 order, however, the draft SPP order includes a preamble stating the CFTC’s intent to preserve “private rights of action” under Section 22 of the CEA.

Representatives of the ISO/RTO Council (IRC), the Public Utility Commission of Texas, the Edison Electric Institute and energy management firm ACES made their case against the preamble language in a hearing of the CFTC’s Energy and Environmental Markets Advisory Committee. No witnesses spoke in favor of the added language.

Undoing the Balance

The preamble could undo “the careful balance of public interests that Congress struck when it directed coordination between the CFTC and the FERC to avoid ‘duplicative regulation’” in the 2010 Dodd-Frank Act, the IRC said in a Feb. 23 letter to the commission.

PJM, ERCOT and CAISO separately raised objections last June. (See PJM: CFTC Order on SPP Undermines Exemption.)

Texas PUC Commissioner Kenneth W. Anderson Jr. told the committee that FERC and the PUCT are more “efficient” than private legal proceedings in resolving disputes. Allowing private actions, he said, would result in “collateral attacks on FERC- and PUCT-authorized valid market rules, undermining the efficient operation and regulation of electricity markets.”

“This provides an end-run around the absence of a private right of action” in the Federal Power Act and Texas Public Utility Regulatory Act, Anderson said.

Uncertainty

“Even if the commission decides to only apply this to the SPP RTO … that still creates a lot of uncertainty for EEI members, primarily because most EEI members operate in more than one RTO,” said Lopa Parikh, EEI’s senior director of federal regulatory affairs.

She noted that the commission did not address whether products such as financial transmission rights and virtual trades are subject to the CEA. “And so now to have the possibility of a number of district courts and lower-level courts opining on this decision further creates regulatory uncertainty,” Parikh said.

Administration of FTRs “would no longer be clearly linked to the underlying physical attributes of the grid, as it inevitably would be argued that FERC was divested of jurisdiction over these products due to the ‘exclusive jurisdiction’ provisions of the CEA,” the IRC said. “Such an outcome would create, for the first time, a ‘regulatory gap’ between the allocation and trading of the product itself and its use in addressing real-time congestion on the grid, a matter clearly within FERC’s jurisdiction.”

Jeff Walker, senior vice president and chief risk officer for ACES, said there was no evidence for a “public interest determination” to add the private rights language to the SPP order.

“Nothing indicates the RTO markets … are opaque pools of interconnected financial entity transactions or instruments,” said Walker, whose company has load-serving entities in five of the seven ISOs and RTOs.

Walker described a scenario involving a generation owner that purchases hedges before taking an outage to repair tube leaks in its boiler.

“Coincidentally, local RTO prices spike,” causing losses for another market participant that held a short physical position and wasn’t expecting the spike. “What does it do? It files a Section 22 action against the generation owner for market manipulation in one of the 100 or so federal district courts.

“Section 22 does not require the plaintiff to prove that the generation owner was not acting in a prudent utility practice manner when scheduling the repair outage,” Walker said. “That is legal uncertainty.”

Separate Rulemaking?

Several witnesses said if the CFTC addresses the private rights issue, it should be done in a separate rulemaking.

“Having worked a lot on these issues in the years right after the passage of Dodd-Frank, there were times when the relations between the CFTC and the FERC were rocky. I think we’ve come into a period of relative calm more recently, which I think those in the industry have welcomed,” said Sue Kelly, president of the American Public Power Association.

“There’s no one from FERC here, so let me just say for them, this could really ruffle some feathers,” she continued. “So I think if you are going to tread into this area, you need to do so very carefully and respectfully of the two agencies’ jurisdiction and have a real full airing of this issue.”

Commissioners Appear Split

All three of the current CFTC commissioners began their terms in 2014, after the 2013 RTO exemption order.

The draft SPP order, published last May, said, “It would be highly unusual for the commission to reserve to itself the power to pursue claims for fraud and manipulation … while at the same time denying private rights of action and damages remedies for the same violations.

“Moreover, if the commission intended to take such a differentiated approach … the RTO–ISO order would have included a discussion or analysis of the reasons therefore,” it continued. “Thus, the commission did not intend to create such a limitation, and believes that the RTO–ISO order does not prevent private claims for fraud or manipulation under the act.”

Commissioner J. Christopher Giancarlo expressed concern over the private rights language in his opening statement. “Commenters have warned that permitting private suits will undermine regulatory certainty and could result in collateral attacks on the finely calibrated electricity market structure that state and federal regulators have enacted,” he said, citing a CEA Section 22 suit by Aspire Commodities and Raiden Commodities against GDF-Suez Energy North America for allegedly manipulating electricity prices in ERCOT. A district court judge dismissed the case in February 2015 based on CFTC’s exemption order, a decision upheld by the 5th Circuit of Appeals last week.

But Chairman Timothy Massad indicated less sympathy for the witnesses’ concerns over litigation to which regulators are not a party and the risk of conflicting district court rulings. “We face that every day … so I don’t think that issue is really unique here,” he said.

“We certainly want to balance the value of regulatory certainty with the need to make sure there is adequate recourse for private actors. The CEA does provide for private rights of action,” he added.

He also indicated no interest in starting a separate rulemaking on the issue, saying, “I think we have taken a lot of public comments on this in the context of the SPP order.”

Commissioner Sharon Y. Bowen was noncommittal, saying only that she wanted to hear market participants’ concerns.

March 1, 2016

Federal Briefs

Michigan Attorney General Bill Schuette is asking the U.S. Supreme Court to enforce its ruling last year and order EPA to put its Mercury and Air Toxics Standards on hold.

Schuette asked the court to issue a stay on the four-year-old mercury rule, which he said it invalidated in its Michigan v. EPA decision last year. In the decision, the court supported Michigan’s position that the mercury rule did not sufficiently consider the adverse economic impact the standard would impose. “We are simply asking the court to enforce its ruling and require the EPA to follow the law like everyone else,” Schuette wrote in a statement.

According to Schuette, the D.C. Circuit Court of Appeals “has failed to vacate the unauthorized rule, leaving it in place with the same force of law despite the Supreme Court’s rejection of it.” His office filed the request last week with Chief Justice John Roberts.

More: MLive

Bay Calls Energy Storage Potential ‘Game Changer’

FERC Chairman Norman Bay last week said energy storage has the potential to become a “game changer” when it comes to economic benefit and system reliability. Bay said the commission will need to manage ways to bring the new technology into the nation’s grid.

“Developments in storage have the potential to bring economic and reliability benefits to consumers, perhaps even to be game changers,” he told an audience at the IHS CERAWeek conference in Houston. “Everybody recognizes costs will decline, but the question is how much and how soon.”

More: Fuelfix Blog

Offshore Drilling Regulation to be Finalized Soon

The federal government is due to release a new rule meant to prevent offshore wellhead blowouts such as the one that caused the 2010 Deepwater Horizon disaster in the Gulf of Mexico.

The Interior Department’s chief of staff, Tommy Beaudreau, told a Columbia University audience that a new rule has been in the works since the disaster. “We’ve been working ever since to try to develop new standards and new rules with respect to well control, both with respect to that critical piece of equipment, the blowout preventer,” he said.

Blowout preventers are designed to pinch shut well piping near the head in the event of a blowout. The Deepwater Horizon blowout preventer did not work.

More: The Hill

Trump’s Plan for EPA: Scrap the Whole Agency

Presidential contender Donald Trump last week shared a proposal if he gets elected: scrap EPA.

“Environmental protection — we waste all of this money,” he said during Thursday’s Republican debate. “We’re going to bring that back to the states. We are going to cut many of the agencies, we will balance our budget and we will be dynamic again.”

While he was short on details, such as who or what would oversee environmental policy in the absence of the agency, he said eliminating it would save $8 billion, its entire annual budget.

More: The Guardian

Lamar Alexander Calls for End to Nuclear Waste Stalemate

Tennessee Sen. Lamar Alexander, speaking at a Senate Appropriations Subcommittee, said it is critical for the country to finally develop and execute a program to handle nuclear waste and called for the moribund Yucca Mountain project to be restarted.

“At a time when everyone wants to produce more carbon-free electricity, it makes no sense whatsoever to undermine this source of power by continuing this logjam and not opening Yucca Mountain to dispose of used nuclear fuel,” the Republican said during a subcommittee hearing on the Obama administration’s proposed budget for the Nuclear Regulatory Commission.

He said he would call for a pilot program to designate consolidated storage sites for used nuclear fuel until a permanent repository is developed.

More: The Chattanoogan

Ole Miss Researchers Get $3M to Investigate Spent Fuel Options

The Department of Energy has awarded $3 million to finance the research of two University of Mississippi professors trying to find new ways to monitor spent nuclear fuel that is sealed up in dry-cask storage. Josh Gladden and Joe Mobley, physics professors, are working on ways to use ultrasonic and acoustic methods to monitor spent fuel.

Their methods could make it possible to ensure the fuel is properly stored, without having to open the storage containers. It is necessary to monitor both the fuel inside the casks, and the casks themselves, to make sure they are intact.

“Since quite a few of these casks are nearing the end of their engineered lifetime, the inspection requirement must be fulfilled in the next five years or so,” Gladden said.

More: The Oxford Eagle

Former NRC Commissioner Calls for Change in Reactor Licensing

Former Nuclear Regulatory Commissioner Jeffrey S. Merrifield said it is time to reconsider licensing requirements for advanced nuclear reactors, saying a new model is needed to help drive private sector development.

“Deployment of this new generation of reactors will require a new model, one that is more dynamic and capable of forming private-public partnership in support of private sector innovation,” he told attendees of a technical summit at the Oak Ridge National Laboratory.

“The current framework of U.S. government policy, legislation, regulation and requirements, research and development support, and fee-based licensing is more aligned with past development efforts,” he said. “This is particularly true of the U.S. Nuclear Regulatory Commission licensing process, which presents one of the largest risk factors confronting private developers of advanced reactors.”

More: The Energy Collective

March 1, 2016January 18, 2024

Company Briefs: March 1, 2016

The Arkansas chapter of the Sierra Club released the “2016 Arkansas Clean Air Solution,” which calls on Entergy to shut down Arkansas’ two largest power plants, Independence and White Bluff, by 2027.

Sierra Club said the plan would help the state meet federal clean air safeguards under the Regional Haze Rule. EPA is set to finalize a regional haze plan for Arkansas in August. Under the agency’s proposal, the two plants will be required to significantly reduce emissions of sulfur dioxide.

Entergy has said it plans to stop burning coal at White Bluff by 2028.

More: Arkansas Business

Mississippi Co-op Eyes Large-Scale Solar

South Mississippi Electric Cooperative and Delta Electric Power Association say they are ready to begin generating electricity using a 100-kW solar system recently installed on the eastern edge of the Mississippi Delta. Atlanta-based Hannah Solar installed the 360 panels, which are situated behind Delta Electric’s offices in Greenwood, Miss.

David O’Bryan, Delta Electric’s general manager, said an official commissioning ceremony is scheduled in late March. He said customers in surveys called for more solar plants.

South Mississippi Electric is currently constructing four other similar solar plants in Mississippi, with the goal of partnering with Origis Energy USA to build a large-scale solar facility in southern Mississippi, capable of powering 10,000 homes.

More: Mississippi Business Journal

PSEG Solar Source Buys 36-MW Plant in Colorado

PSEG Solar Source, PSEG’s merchant solar generation arm, bought a 36.3-MW solar project in Colorado from juwi Inc. The $54 million acquisition brings the company’s total solar portfolio to 16 utility-scale projects.

The PSEG Larimer Solar Energy Center is about 25 miles north of Fort Collins, Colo., and has a 25-year power purchase agreement with the Platte River Power Authority. The project was originally called the Rawhide Flats Solar facility. It was built on a 290-acre site own by PRPA. Construction is scheduled to be completed by the end of this year.

“We are delighted to be a part of an initiative that contributes to growing Colorado’s clean energy supply,” said Diana Drysdale, president of PSEG Solar Source.

More: PSEG

LG&E, KU Install 10,000 Smart Meters

Louisville Gas & Electric and Kentucky Utilities have offered a limited number of free smart meters for residential and small business customers. The new meters are linked to a website that allows customers to monitor their electricity usage in 15-minute increments. The PPL-owned utilities say the meters will allow customers to better understand their electric consumption.

The program is limited to the first 5,000 LG&E and 5,000 KU customers who enroll. The utilities said they will track participation and interest levels this year to determine if the program should be continued.

The smart meter installation program is separate from KU’s demand conservation program, which uses a device attached to central air conditioning and heat pumps to temporarily interrupt service on peak days to reduce system load.

More: Lexington Herald-Leader

Dairyland, Xcel Announce Plans to Double Wisconsin’s Solar

Dairyland Power Cooperative and Xcel Energy have announced plans that will add almost 22 MW of solar capacity in Wisconsin, doubling the amount of utility-scale solar generation in the state.

Dairyland is buying the output from 12 solar arrays with a combined capacity of almost 19 MW. Xcel has entered into contracts to purchase the output of solar gardens in the western part of the state for about 3 MW.

Xcel is adding solar throughout the Midwest and said it plans to have more than 250 MW of solar in Minnesota by the end of this year.

More: LaCrosse Tribune

Chesapeake Energy not Drilling in Ohio Anymore

Once the biggest natural gas driller in Ohio, Chesapeake Energy no longer has any rigs operating in the state. The nation’s second-largest gas producer, which has been shedding assets and cutting costs in the face of low energy prices, announced fourth-quarter losses of $2.2 billion, compared to $639 million in profits the year before.

While many oil and gas drilling companies are scaling back, few have shown such a drastic reduction in Ohio’s Utica shale fields as Chesapeake. Two years ago, the Oklahoma City company had 64 rigs operating across the country. It now plans to operate four to seven nationwide.

More: Columbus Business First

Exelon Wind Turbine Collapses During Snowstorm in Michigan

A wind turbine at an Exelon wind farm in Huron County, Mich., collapsed during a snowstorm last week but caused no injuries or damage, county and company officials said.

The turbine toppled about 5 a.m. on Thursday during a period of high winds and heavy snow. The closest residence is about 2,200 feet from the fallen turbine and mast. Company officials said an investigation is underway to determine the cause.

More: Mlive

PSEG Names New President of PSEG Nuclear

Peter Sena, who has held a number of executive and operational positions at FirstEnergy and NextEra Energy, has been named president of PSEG Nuclear. He will report to PSEG Power President William Levis.

Sena comes to PSEG from NextEra, where he was senior vice president of operations and chief operations officer. Before that, he spent 15 years with FirstEnergy’s nuclear generation organization.

He is a U.S. Navy veteran and holds a degree in fuel science from Pennylvania State University. He has served as a member of Penn State’s Nuclear Engineering Advisory Board and currently serves on Auburn University’s advisory board.

More: PSEG

March 1, 2016

ERCOT Technical Advisory Committee Briefs

ERCOT’s Technical Advisory Committee last week tabled a proposal to pay lost opportunity costs to generators ordered to ramp down for grid reliability, choosing instead to take advantage of extra time on the calendar and schedule a workshop on the issue.

The Board of Directors remanded the proposal (NPRR649) back to the TAC in February. It had received 56% support in a TAC roll call vote in November, short of the two-thirds threshold for approval. (See LOC Rule Sent Back to ERCOT’s Stakeholder Process.)

The TAC set March 7, 9 or 23 as possible dates for the workshop. The committee doesn’t meet again until March 31, giving it a month and a half before it must report back to the board April 12 with either a final version of NPRR649, an alternative version or reasons for rejecting it.

TAC Chair Randa Stephenson said she would prefer an early workshop, but she also wanted to ensure ERCOT staff had enough time to draft language that helps the committee develop alternative recommendations.

Kenan Ögelman, vice president of commercial operations, said the delay would give staff ample time to write a new nodal protocol revision request that would be an “option B.”

“It would be very different from the existing 649,” Ögelman said. “We would like to spend more time on option B and describe it better.”

Staff is working on what Ögelman called “attestation language” that better describes the circumstances of ramping down units in the day-ahead market.

The attestation language “needs to be broad enough to cover the multiple ways people use their units for hedging purposes,” Denton Municipal’s Lance Cunningham said.

DREAM Task Force Submits Final Report

The TAC told its Distributed Resource Energy Ancillaries Market (DREAM) Task Force to develop a matrix of “actionable, clear points” for the committee to consider at its April meeting.

The committee was responding to the final report of the task force, which was chartered to analyze the regulatory and market framework governing distributed generation resources’ participation in ERCOT.

The report sought the TAC’s direction on eight policy questions that might be put to stakeholder votes. Ögelman told the committee ERCOT would like to merge a staff white paper with the DREAM team’s work before going through the stakeholder process.

“We would like to start working on NPRRs and other potential changes,” Ögelman said. “We would like to engage stakeholders further on an individual basis as we work through the issues.”

“I want to be clear on exactly what DREAM and ERCOT are asking TAC to do with this information, the items in the white paper and presentation,” said Diana Coleman, senior market specialist with the Texas Office of Public Utility Counsel.

ERCOT, which has a little more than 550 MW of DG, is projecting those resources will grow by 10% annually.

The task force said ERCOT lacks explicit rules for DG resources 10 MW or greater that are connected at a distribution voltage, and that intend to inject into the distribution system rather than reduce load. It also needs a more precise definition of the term “customer,” the task force said, citing “ambiguous reference[s] to distribution customer, load, etc.”

“These are rapidly growing, very flexible resources,” said Shell Energy’s Greg Thurnher, the task force chair. At 10% growth, he noted, ERCOT would essentially be adding the capacity of a nuclear unit similar to those at the South Texas Project over about seven years.

Thurnher said the wide disparity of business interests and opinions within the DREAM team “make it difficult to make further progress — absent a voting structure.”

ERCOT has DG resources in more than 7,600 locations in competitive areas. Its congestion revenue rights software can only handle about 600 resource nodes at a time.

“There are computing constraints to how large we can make this system,” Thurnher said.

“The key to the nodal market is having as much visibility into the market as possible,” Calpine’s Randy Jones said. “We need to give ERCOT the observability they have to have, and to be able to model” DG resources.

Other stakeholders said the proposed changes are an “unnecessary layer of complexity.” They also discussed optionality between load zone and nodal pricing.

“These types of resources are growing in ERCOT and will have an impact on market solutions,” Ögelman said. “The stakeholders can address the potential growth in distributed resources, and you address those by having market rules.”

Regional Haze Workshop

The committee and its Wholesale Market Subcommittee agreed to hold a workshop devoted to regional haze and reliability-must-run (RMR) services.

ERCOT staff had proposed a fall date for the workshop, after any potential litigation on EPA’s regional haze rules is settled. However, the WMS and other market participants expressed a desire to hold the workshop earlier.

“You’re not getting anything by fall from the courts,” Stephenson said.

“If [market participants] are more focused on the RMR aspects of it, we can have the workshop sooner, rather than later,” Citigroup Energy’s Eric Goff said. “If you’re talking about the regional haze aspect, that’s a lot of moving parts.”

Goff noted that EPA dismissed ERCOT’s concerns about reliability implications, saying, “If ERCOT doesn’t have enough notice on RMR operations, maybe it should change the notice of suspension requirements.

“I don’t know if they considered the kind of Pandora’s box that opens,” he said. “ERCOT could benefit from the market’s input on fleshing out the protocol language.”

Ögelman said ERCOT staff would commit to coming back to the TAC and reviewing the RMR processes, but that its answers might be different.

“ERCOT needs to bring their concerns and ideas,” Stephenson said. “The stakeholders have their concerns. Now, we need ideas and solutions.”

Ancillary Service Redesign Project

ERCOT staff is conducting an additional cost-benefit analysis on the ancillary service redesign project and should be done in time for the Protocol Revisions Subcommittee’s March meeting, ERCOT’s Kenneth Ragsdale told the TAC.

While ERCOT has been successful in complying with NERC reliability standards, its ancillary service framework, which dates back to the late 1990s, “does not adequately address ongoing changes to the ERCOT system,” nor does it anticipate those in the future, such as DG and utility-scale intermittent renewables, according to NPRR667.

“ERCOT still believes 667 has some worthy concepts in it,” Ragsdale said.

He said staff is considering phased transition plans for the NPRR, allowing it to be implemented sooner.

Reserve Discount Factor Proposal

ERCOT staff told the committee it will be recommending changes to the reserve discount factors (RDF) used in its physical response capability calculation as a result of unannounced testing conducted in 2014-15.

When temperatures are below 95 degrees, staff is suggesting a resource’s high sustained limits (HSL) should not be discounted. However, when temperatures exceed 95 degrees, HSLs would be discounted, but only by 1%, instead of the current 2%.

Manager of Operations Planning Sandip Sharma said ERCOT would recommend procuring additional responsive reserves when temperatures are above 95 degrees.

Amanda Frazier, senior director of regulatory policy at Energy Future Holdings, said her company analyzed 12 months of data and found similar results to ERCOT’s. “We did see a difference in the high hours,” she said. “But does it make sense to reduce the RDF to zero in hours not above 95?”

Calpine’s Jones questioned ERCOT’s motivation. “If you’re producing more [responsive reserves] for price formation, just say so,” he said.

Ögelman responded that the idea behind the change was “not necessarily” price formation, but the 1% discount factor.

“There’s evidence we should wait a bit, and there’s evidence we should reduce it all the way to zero,” he said. “In the proposal, it can only come down 1%. I would point to the existence of reserve discount factors as the driver for action.”

ERCOT staff will take the proposal back to the Reliability and Operations Subcommittee. According to the staff timeline, the issue will come back to the TAC in April.

NPRRs, Subcommittee Goals Approved

The TAC approved its goals and strategic objectives for 2016, along with the goals of its Commercial Operations, Reliability and Operations, and Wholesale Market subcommittees.

The committee also easily approved two NPRRs and a system change request, along with a nodal operating guide revision request it had tabled in January.

NPRR749, Option Cost for Outstanding CRRs.
NPRR750, Clarify Resource Status when Providing Fast Responding Regulation Service.
SCR787, Maintain NDCRC Data for Generator Transfer Between Resource Entities.
NOGRR143, Alignment of Nodal Operating Guiders with NERC Reliability Standard, BAL-001-TRE1.

Budget Issues

The Protocol Revisions Committee told the TAC that ERCOT has raised its internal labor rate from $65/hour to $75/hour in calculating impact-analysis cost estimates and project labor costs for staff who work on capital projects. The PRS said the old rate had been in effect for more than 10 years.

ERCOT has allocated a $400,000 contingency fund for 2016-17 market projects to ensure board-approved revision requests are not delayed. The change does not affect the system administration fee.

Leadership Posts Filled

The TAC unanimously approved the re-election of Adrianne Brandt as its vice chair. Brandt left Austin Energy for San Antonio’s CPS Energy shortly after the year began, requiring a second vote from members before she could officially take her position.

The committee also approved the Retail Market Subcommittee’s leadership (Chair Kathy Scott of CenterPoint Energy and Vice Chair Rebecca Reed Zerwas of NRG Energy) and that of its four working groups and task forces.

— Tom Kleckner

March 1, 2016

FERC Denies Rehearing of Winter Reliability Order

By William Opalka

FERC on Wednesday denied rehearing of its September order endorsing the interim Winter Reliability Program for ISO-NE (ER15-2208).

The commission had endorsed a proposal made by the FERC Asked to Determine ISO-NE Winter Reliability Program.)

NEPOOL’s proposal was based on the 2014/15 winter program — which provided compensation for any unused oil or LNG remaining at the end of the winter — and added demand response.

ISO-NE’s proposal provided compensation for unused oil or LNG, but it would have also compensated nuclear, hydro, biomass and coal-fired resources and did not include DR.

Entergy had challenged the order, saying FERC’s stated preference for a market-based solution to mitigate winter natural gas supply constraints should have tipped the balance toward the RTO’s more fuel-neutral program.

“The record reflects that including such resources in the program would not provide any additional winter reliability benefit to the region,” the commission wrote. “While Entergy argues that additional payments to coal, nuclear and hydro resources would likely incentivize these resources to take incremental measures to ensure performance during the winter, this assertion is contradicted by substantial expert testimony supporting the NEPOOL proposal.”

FERC repeated its assertion that it prefers market-based solutions, but it said an out-of-market solution is “appropriate” until ISO-NE’s Pay-for-Performance program begins later in early 2018.

Shortly after the September order, Entergy’s Pilgrim nuclear plant in Massachusetts was removed as a capacity resource for the 2019/20 commitment period. It will be closed no later than 2019. (See Entergy Closing Pilgrim Nuclear Power Station.)