Page 1458 – RTO Insider

April 11, 2016

Idaho Power Inks Agreement to Join Western EIM

By Robert Mullin

Idaho Power on Wednesday signed an agreement with CAISO to become the sixth utility to join the western Energy Imbalance Market (EIM).

The Boise-based company, which serves about 525,000 customers in southern Idaho and a portion of eastern Oregon, expects an April 2018 start date, pending approval from federal and state regulators.

Inclusion of Idaho Power would bring an additional 4,800 miles of transmission into the EIM while improving the market’s access to an area of Wyoming that renewable developers — including EIM member PacifiCorp — seek to tap for wind projects intended to serve the West Coast.

“The market already has proven itself to increase network efficiency, lower costs and encourage cleaner energy into the power grid,” CAISO CEO Steve Berberich said in a statement. “With each new entrant, the market will only multiply those benefits.”

CAISO launched the EIM in November 2014 in partnership with the Portland-based PacifiCorp, which operates more than 16,000 miles of transmission spanning 10 states. Unlike in an RTO, the EIM’s transmission-owning entities retain operational control over their assets, while member generators participate in the real-time market on a voluntary basis.

Nevada-based NV Energy joined the EIM in December 2015, broadening the market’s footprint and filling a transmission gap between load centers in California and generating resources located in the PacifiCorp East (PACE) balancing area. (See NV Energy has Smooth EIM Integration, CAISO Says.)

“With the entry of NV Energy, [CAISO] transfer capacity with PACE has gone from around 200 MW to 571 MW,” Eric Hildebrandt, CAISO director of market monitoring, said during an April 6 Regional Issues Forum held in Portland. “This has really been a game changer.”

Idaho Power’s membership could provide a similar — if more limited — enhancement to the market. The utility’s service territory sits adjacent to both the NV Energy and PACE balancing areas, providing increased transfer capability with the remote northeastern corner of PACE, the wind-rich area of western Wyoming.

Although wind developers see the region as a promising source of wind exports, transmission constraints — and California’s restrictions on renewable imports not delivered directly into an in-state balancing area — have impeded development of large-scale projects to serve California. Idaho’s entry into the EIM, along with possible ISO membership for PacifiCorp, could open the door for development as CAISO’s boundary effectively extends eastward, expanding RPS eligibility for a larger pool of resources.

In a deal that seemed to anticipate yesterday’s announcement, Idaho Power and PacifiCorp last year swapped $43 million in Idaho and Wyoming transmission assets, reallocating ownership of lines and equipment designed to move power westward from the massive Jim Bridger coal-fired generating plant. One result of the deal: PacifiCorp gained access to an additional 200 MW of “dynamic service” out of western Wyoming, short-term transfer capability that facilitates integration of variable renewable resources. For its part, Idaho Power expected the new arrangement to boost its transmission revenues, reducing the company’s revenue requirement from ratepayers.

Two other Northwest utilities will precede Idaho Power into the EIM. Washington-based Puget Sound Energy is scheduled to join this October, followed by Portland General Electric in October 2017.

April 11, 2016

MISO Market Subcommittee Briefs

MISO will not build an application programming interface (API) to provide five-minute schedule data to customers.

“MISO is not recommending to pursue this function at this time,” MISO’s Matt Schingle said during an April 5 Market Subcommittee meeting.

At the December MSC, Kansas City Power and Light requested creation of an API to retrieve market participants’ physical schedules from webTrans or the e-tag system.

Schingle said too few stakeholders wanted the change for it to be cost-effective. “This year, there’s not enough flex in the budget for this kind of cost,” he said. MISO’s vendor estimated the API would cost $150,000 to develop.

Schingle said the raw data is already available through customers’ internal market software, although MISO does not provide a function allowing customers to retrieve schedule profiles.

MISO Moves Ahead on PJM Coordinated Transaction Scheduling; Monitor Slams PJM Fees

MISO could begin publishing monthly price forecasts for MISO-PJM Coordinated Transaction Scheduling (CTS) as early as May 13, according to Beibei Li of MISO’s market evaluation and design team.

Designed to reduce uneconomic power flows, CTS will allow traders to submit bids that would clear only when the price difference between MISO and PJM exceeds a threshold set by the bidder.

Li said MISO expects to publish the final CTS price forecast report template by April 22 and is seeking MSC feedback by April 19.

Dave Johnston of the Indiana Utility Regulatory Commission asked if CTS transactions would be subject to uplift. Li said MISO did not believe that uplift charges would apply.

CTS came under criticism in a recent Independent Market Monitor quarterly report, with Monitor David Patton contending the program is currently “accomplishing very little” because of poor forecasting and fees imposed by PJM. Patton said PJM’s charges at the seams were similar to MISO’s revenue sufficiency guarantee payments.

While Patton said the Monitor supports MISO’s FERC filing to add CTS to its Tariff (ER16-533), his group filed comments asking the commission to require that PJM eliminate all uplift charges. MISO has already proposed excluding charges such as the revenue sufficiency guarantee and revenue neutrality uplift.

Patton said CTS is “much more liquid and effective” without uplift charges, as illustrated by trading across NYISO’s seams with ISO-NE and PJM.

“We’re hoping that FERC reads our filing and orders PJM to eliminate all charges,” he said.

The Monitor is also working with MISO and PJM to develop proposals for firm capacity delivery as an alternative to pseudo-tying resources to PJM, Patton said.

“I continue to be amazed that PJM thinks this pseudo-tie requirement is necessary,” he said. “They’re not thinking of what’s best for the Eastern Interconnect.”

MISO will pseudo-tie about 2,000 MW of new generation into PJM for the 2016/17 planning year and more than 2,500 MW during the next two planning cycles. Only 155 MW of new generation was pseudo-tied in the 2015/16 planning year.

Need for 30-Minute Reserve Product Questioned

MISO is revisiting the merits of developing a 30-minute reserve product despite stakeholder questions about the need for the requirement.

The RTO is reviving the idea because natural gas generators are being used increasingly as baseload resources, rather than just meeting peak demand.

MISO has assigned the project “medium” priority on its Market Roadmap, with evaluation expected to be complete by the end of the third quarter, according to Leonard Ashley of MISO’s market evaluation and design team. He said the project would emerge as a major market implementation if developed.

The 30-minute reserve product would be designed to respond to a large loss of generation within a constrained area, said Jeff Bladen, executive director of market design. He said the product was a “necessary evolution of market design” and could address systemwide reliability instead of local reliability.

Bill SeDoris, director of MISO integration for Northern Indiana Public Service Co., asked if the issue could be solved simply with use of an increased reserve requirement.

“That’s one way to do it,” MISO’s Kevin Larson responded. “I don’t think that’s the most economic way to do it.”

Bladen said the RTO’s initial assessment shows that creating a 30-minute reserve is less costly than carrying additional spinning reserves or regulation reserves.

Thomas Sikes of WPPI Energy asked if MISO could replicate its 2013 report that concluded a short-term reserve product was unnecessary.

Ashley said MISO is just beginning to evaluate the project, and conceptual design wouldn’t start until late this year.

“We didn’t mean to give the impression that the ship has been built and set sail. … We definitely haven’t made the decision that a 30-minute product is the way to go,” Ashley said.

FTR Working Group may be Absorbed by MSC

Brad Arnold, chair of the Financial Transmission Rights Working Group, said his group is considering merging with the Market Subcommittee due to light agendas and infrequent meetings. The group last met Jan. 8.

Arnold said the working group would meet to discuss possible 2016 initiatives and figure out if there are enough to justify the group’s existence.

MISO to Hold August Market Symposium

Bladen reported that MISO would hold a first-ever market symposium Aug. 18-19. Bladen said the symposium would center on two main themes: shifting environmental regulations (Day One) and the future of distributed resources (Day Two). He said the symposium will be “taking the temperature” of the industry by bringing in experts from around the country to speak.

Registration instructions will be posted sometime this week.

The MSC also approved the Seams Management Working Group’s largely unchanged charter.

— Amanda Durish Cook

April 11, 2016

FERC Rejects Challenge to Michigan Wind Farm’s GIA

By Amanda Durish Cook

FERC last week rejected Michigan Electric Transmission Co.’s rehearing request regarding a western Michigan wind farm’s interconnection agreement with MISO (ER16-33-001).

Michigan Wind Farm - Lake Winds Energy Park (Lake Winds Energy Park) — Lake Winds Energy Park *Source: Lake Winds Energy Park*

The April 6 order concerns Consumers Energy’s 100-MW Lake Winds Energy Park, which went into operation in 2012. METC argued that the generator interconnection agreement was executed in violation of MISO’s queue procedures and FERC Order 2003, which standardized interconnection agreements.

Lake Winds is interconnected to power lines that were classified as state-jurisdictional distribution facilities when it went into operation. Last April, FERC granted Consumers’ request to reclassify those lines to commission-jurisdictional transmission facilities.

METC said the order created a “jurisdictional loophole in the commission’s interconnection rules” because it permitted a wholesale generator to follow state interconnection procedures.

“What METC argues is a ‘loophole’ is a description of the jurisdictional boundary between federal and state interconnection rules, including Order No. 2003,” FERC wrote in rejecting its request.

FERC also said Order 2003 doesn’t apply to the MISO and Lake Winds GIA. “Order No. 2003 did not govern the interconnection of the Lake Winds facility in 2012, and therefore MISO’s queue procedures implementing Order No. 2003 similarly did not govern the project’s interconnection at that time,” the commission wrote.

METC had argued that the commission’s determination that Lake Winds’ interconnection was not subject to Order 2003 was arbitrary and capricious.

April 11, 2016

PJM Planning Committee and TEAC Briefs

VALLEY FORGE, Pa. — Interconnection customers would be required to provide more documentation earlier to ensure consideration of their projects under proposed changes to the queue submittal process.

The recommendations came out of the Earlier Queue Submittal Task Force, which was convened after current rules — which charge nonrefundable fees that escalate later in the queue window — were found to be ineffective in incenting earlier applications. (See “Still Searching for Ways to Incent Early Project Submissions,” PJM Planning Committee Briefs.)

Early on, the task force decided that it would have little luck trying to change human behavior and instead focused on the objective of being able to start building models for the projects, PJM’s Dave Egan said.

The thinking led to a number of proposed changes.

Currently, queue priority is assigned based on the date the application and deposit are submitted, and supporting documentation is not required. Under the new rules, priority would not be secured until all required elements of a project, including site control, were submitted.

PJM would perform a deficiency review only after all the elements, aside from site control, were in hand.

Applications would have to clear their deficiencies by the close of the queue window or be terminated. PJM would codify in the Tariff that it has five business days to review a deficiency response.

Project deposits would become chargeable immediately upon application, and instead of socializing the cost of applications that fail to clear their deficiencies, PJM would charge the customer.

Instead of having a different fee structure for large generation and small generation, the nonrefundable amount would be 10% of the overall fee for all projects, and the refundable portion would be spent by PJM first.

PJM also proposes to move the opening of queue windows to April from May and to October from November as soon as this fall. That will improve the opportunity of generation to participate in the May Base Residual Auction, Egan said.

The Planning Committee will be asked to vote on the changes in May.

Reference Model for CPP Study Introduced

PJM introduced the reference model it will use to study the economic and reliability implications of the Clean Power Plan.

The initial review will look at the next 20 years and provide potential scenarios driven by policy, regulation and the market. (See PJM to Proceed on CPP Study Despite Supreme Court Ruling.)

The study was requested by the Organization of PJM States.

PJM PC & TEAC — PJM’s energy and capacity prices and its generation mix would be affected by differing Clean Power Plan scenarios.

At Thursday’s Transmission Expansion Advisory Committee meeting (TEAC), PJM also presented results of sensitivities conducted on the reference model that assumed state renewable portfolio standards and gas prices averaging $3.43/MMBtu through 2037. (The reference case assumes an average of $5.14/MMBtu.)

Among the key observations, PJM found that high capacity prices will allow natural gas combined cycles to enter the market despite low energy prices, while coal and nuclear resources will increase their dependence on the capacity market to recover their costs.

Wind and solar will be able to grow in a low-gas-price environment as long as renewable portfolio standards are enforced. PJM also predicts that lower gas prices will result in a reduction of carbon emissions through increased retirements of coal plants and the entry of new gas combined cycle plants.

PJM expects to release a final report by the end of May.

Year’s First Proposal Window Draws 26 Projects

The first competitive transmission proposal window of the year drew 26 projects from seven entities.

The projects address generator deliverability, common mode outage violations and end-of-life facilities.

Three are transmission owner upgrades ranging in cost from $7.7 million to $48.5 million. Twenty-three are greenfield projects with cost estimates of $15.6 million to $111.5 million.

More details will be provided at a future TEAC meeting.

PJM collected about $190,000 to study the projects under its new proposal fee structure. (See “Two-tiered Fee Schedule for Order 1000 Projects OK’d,” PJM Markets and Reliability Committee Briefs.)

Proposal Would Exclude TO Upgrades from Order 1000 Window

PJM is proposing to exclude certain transmission owner upgrades from the Order 1000 competitive window process. They include typical short-circuit violations and fixes to substation terminal equipment such as wave traps, current transformers and capacitors.

“We’re looking at situations where the upgrade is only a modest upgrade to equipment inside a substation,” said Steve Herling, PJM vice president of planning. “Our intention is to not have a window for something we know can be easily fixed.”

Few baseline projects driven by short circuits have resulted in a greenfield project, said PJM’s Mark Sims, who plans to present proposed changes on a first read next month at the Planning and Markets and Reliability committees.

– Suzanne Herel

April 8, 2016

Seventh Circuit Court Upholds FERC Order 1000 ROFR Provisions

By Rich Heidorn Jr.

A federal appeals court Wednesday unanimously upheld FERC Order 1000’s right-of-first-refusal provisions, rejecting challenges from the MISO Transmission Owners and LSP Transmission Holdings.

The 7th Circuit Court of Appeals in Chicago ruled after consolidating a challenge by the transmission owners, who sought to preserve the ROFR in the MISO transmission agreement (14‐2153), with two by LSP that contended FERC did not go far enough in injecting competition into transmission development (14‐2533, 15‐1316).

MISO ROFR

The three-judge panel was especially critical of the TO’s challenge to Order 1000’s requirement that federal ROFRs be removed from FERC jurisdictional tariffs. Invoking the Mobile-Sierra doctrine, the TOs said FERC should presume that their contractual ROFR is reasonable.

Richard_Posner_at_Harvard_University - for web (Wikimedia) — 7th Circuit Court of Appeals Judge Richard A. Posner

“But why?” Judge Richard A. Posner asked in the opinion. “The owners have made no effort to show that the right is in the public interest. Neither in their briefs nor at oral argument were they able to articulate any benefit that such a right would (with limited exceptions …) confer on consumers of electricity or on society as a whole. … Contract rights are not sacred, especially when they curtail competition.”

The TOs contended that their ROFR was not intended to prevent competition but to give MISO power to require TOs to build needed facilities in their service territories. “But that makes no sense,” the court said. “Had there been no intention or expectation of competition, there would have been no need for a right of first refusal.”

Baseline Reliability Projects

In the second case, LSP asked the court to overturn FERC’s decision to allow a TO the right to build any baseline reliability projects whose costs are allocated to that company’s territory alone and not subject to regional cost allocation. FERC justified this exception on the grounds that requiring competition on such projects — which often require quick turnarounds — could lead to delays because of the time required to conduct bidding and the potential for litigation by losing bidders.

LSP said reliability projects covering more than one pricing zone should be considered regional and thus open for competition.

“But a transmission facility is not regional for purposes of cost allocation if all its costs are allocated to the pricing zone in which it is located,” the court said. “A right of first refusal would be problematic, therefore, only if the benefits of a baseline reliability project were largely or entirely realized in pricing zones other than the one in which the project was to be built.”

State ROFRs, Entergy

LSP raised a related complaint in the third suit, challenging FERC’s decision to treat the entire Entergy footprint — Texas, Arkansas, Louisiana and Mississippi — as a “local” area not subject to competition and regional cost allocation.

“The vast region covered by Entergy’s multiple operating companies hardly complies with the usual understanding of ‘local,’” the court acknowledged. “But ‘local’ need not retain its usual understanding when used to designate the service area of a giant electrical transmission entity. It is a relative term; New York City is a huge city yet as a matter of scale is ‘local’ relative to New York state, or to the Northeast. Entergy’s retail distribution service territories can be said to be ‘local’ for a different reason: the separate operating companies actually operate as one and have so operated for more than 50 years.”

LSP also challenged FERC’s approval of MISO rules implementing Order 1000, including its rules for evaluating competitive bids, which consider not only the project’s estimated cost but also its design and the quality of the bidder’s management.

The court rejected LSP’s desire to make cost the primary criteria for selection, saying, “There is no indication that any of MISO’s criteria favor incumbent developers over nonincumbent ones who have demonstrated an equal ability to execute a project effectively.”

The judges also upheld MISO’s acknowledgment of state ROFRs, over which FERC has no jurisdiction. LSP cited a Minnesota law that grants an incumbent TO the right to construct, own and maintain any lines that connect to the TO’s system.

“It would be a waste of time for MISO to conduct a protracted competitive bidding and evaluation process when the incumbent transmission company has a right of first refusal conferred by state law,” the court said.

The 7th Circuit’s ruling is the second to uphold Order 1000’s removal of federal ROFRs, following one by the D.C. Circuit Court of Appeals in August 2014 that consolidated more than a dozen cases. (See FERC Order 1000 Upheld.)

There are at least six pending cases involving compliance by PJM, Columbia Grid, ISO-NE, SPP and WestConnect in the D.C. Circuit and the 5th Circuit, according to FERC.

April 4, 2016

NYISO Management Committee Briefs

New York’s natural gas demand set a single-day record in February, although the winter was much milder than the average over the past 30 years.

The winter operations review presented at the NYISO Management Committee meeting on Wednesday showed that only three relatively brief cold snaps occurred over the winter, with the worst one in mid-February. Cold snaps in December and January, when daylight hours are shorter, have greater potential to stress the electric system, said Wes Yeomans, NYISO’s vice president of operations.

On Feb. 13, during the coldest three-day period of the winter, the ISO set a 6.6 Bcf single-day record for natural gas demand, exceeding the previous mark of 6.4 Bcf set in February 2015. Yeomans said 100% of the natural gas system’s capacity was reached that day, for both heating and electricity generation.

The record was as much a function of the low cost of natural gas as power demand, Yeomans said. “Gas prices remained below oil prices for the day,” he said.

NYISO relies heavily on dual-fuel capable generation, so when natural gas supply becomes constrained — or when it becomes uneconomic relative to the cost of oil-fired generation — fuel-switching becomes more widespread. That did not occur during this stretch.

The peak load in mid-February was 22,951 MW. No demand response resources were called upon this winter.

“Our winter peak was below the 50/50 forecast by quite a bit,” Yeomans said. The peak of 23,317 MW on Jan. 19 was the lowest winter peak since at least 2004. The forecasted peak was 24,515 MW.

Yeomans said the fuel-monitoring platform the ISO created to improve reliability also appeared to be “working well.”

ICAP Demand Curve Reset

The committee voted to set the capacity market demand curve every four years with an annual reset, an increase from the current three-year cycle. The demand curve was introduced more than a decade ago.

“The change is recognizing calls from stakeholders,” said Paul Hibbard, vice president of the Analysis Group, the consultant hired by NYISO.

The changes more accurately reflect the New York wholesale market as generation assets enter and leave, Hibbbard said. The annual reset would consider the gross cost of new entry and forecast energy and ancillary services revenues, as well as adjusting historical revenues to reflect market conditions.

Another factor in extending the cycle is the 18 to 20 months needed for setting the demand curve.

The change needs to be ratified by the NYISO Board of Directors. Further refinements would be performed over the next several months, in advance of a filing with FERC by Nov. 30. NYISO anticipates an operational date of May 1, 2017.

— William Opalka

April 4, 2016

Grid 2.0 Asks DC PSC to Reconsider Merger Approval

By Suzanne Herel

One party to the Exelon-Pepco Holdings Inc. merger case has asked the D.C. Public Service Commission to reconsider its approval, and the People’s Counsel said she’s considering doing the same.

Sandra Mattavous Fry (Twitter) - Exelon-Pepco Merger — Mattavous-Fry *Source: Twitter*

Grid 2.0, which advocates for distributed generation, and did not sign on to any proposed settlement in the case, said in a March 25 filing that the commission failed to give adequate notice of public hearings and did not provide support for its finding that the settlement it crafted itself was in the public interest.

“The commission … failed to make any independent finding that the revised settlement agreement is in the public interest,” it said, calling the PSC’s conclusion “arbitrary and capricious.”

The nine settling parties, who approved an initial agreement that was later amended by the commission, have until April 22 to file an application for reconsideration with the PSC. Four other groups that intervened but did not sign on to the settlement also have the opportunity to appeal the decision.

The joint applicants responded to the filing, saying “every part of Grid 2.0’s argument is wrong.”

“The commission approved the merger after two years of the most exhaustive consideration that the commission has ever given to any issue, and it did so based on one of the most extensive records the commission has ever compiled,” they said.

D.C. People’s Counsel Sandra Mattavous-Frye said last week on the Kojo Nnamdi radio show that she is reviewing the ruling with an eye toward issues that might warrant her office taking action.

“I do have some major concerns about the process throughout the case. You didn’t really know what to expect or how the commission came to its determination,” she said. “It’s not over until it’s over. But I do admit that the lift is going to be heavier at this junction.”

Exelon and Pepco closed the $6.8 billion transaction just hours after the PSC approved the deal on March 23. (See Exelon Closes Pepco Merger Following OK from PSC.)

Mattavous-Frye cited “uncertainty created by the commission’s plan,” specifically how it plans to use $32.8 million of the $72.8 million customer investment fund that commissioners “redirected … for themselves without any clear explanation of how those funds will be used.”

If the commission stands by its decision, parties may turn to the D.C. Court of Appeals.

The acquisition, approved on a 2-1 vote with Chairwoman Betty Ann Kane in opposition, creates the country’s largest utility by customer count.

In an interview last week with the Washington Business Journal, Exelon CEO Chris Crane and new Pepco head David Velazquez said they would work to prove themselves to merger opponents and will be active in district affairs.

April 4, 2016

GridEx III Shows Vulnerability of Power Grid to Cyberattack

By Ted Caddell

GridEx III, a drill to test the emergency response capabilities of the North American high-voltage power grid, highlighted several vulnerabilities in the face of a simulated cyberattack. The lesson: Responding to a wide-scale computer malware attack is completely different from overcoming a monster storm.

“Electricity system recovery and restoration would be delayed or may not begin until the nature of the cyber risks are understood and mitigation strategies are available,” said NERC’s final report on the November drill.

GridEx III drew 4,400 participants from grid operators, federal agencies and local, state and federal law enforcement. The two-day scenario hit the grid with cyber and physical attacks resulting in blackouts in several cities. Organizers sent waves of simulated malware to grid operators by email. Throughout the beginning stages of the drill, operators were also notified about simulated attacks on physical plants such as transmission lines and substations.

“We wanted to challenge the coordinators to be on that ragged edge … [to see what they need to do to] protect the reliability of the system,” Bill Lawrence, NERC associate director of stakeholder engagement, said during a press conference Thursday.

The scenario employed email delivery of simulated malware — a tactic used by hackers who attacked three utilities in Ukraine in December. (See How a ‘Phantom Mouse’ and Weaponized Excel Files Brought Down Ukraine’s Grid.)

The after-action reports showed that secure sharing of communication between parties and reporting methods remains a problem.

“Industry needs to coordinate with local law enforcement to identify and assess the physical risks to electricity facilities and workers,” the report said. “Unlike how industry responds to major storms through mutual assistance, industry’s capability to analyze malware is limited and would require expertise likely available from software suppliers, control system vendors or government resources.”

Another observation was that the information-gathering tools may be capturing too much. The NERC-run information portal captured reports in real time, but participants said they and the system quickly became overwhelmed.

NERC, the report said, “should continue to enhance the [information] portal to support real-time, searchable, urgent communication and collaboration.”

Another major observation gleaned from the simulated cyber and physical attack was that recovery would be prolonged and expensive. “Utilities will need unprecedented levels of financial resources in order to restore their facilities and eventually resume normal operations,” the report said.

The massive expense of a widespread restoration effort raised a question: Where is that money going to come from?

“There are certain regulations and laws out there that could be useful for grid restoration,” Lawrence said. “For example, the Stafford Disaster Relief and Emergency Assistance Act is designed to deliver relief and funding to individuals that are impacted by a disaster.”

But the law doesn’t provide relief for private corporations, such as investor-owned utilities. “Obviously if the utility isn’t generating power, they can’t pay their employees, and that would be a severe impact,” Lawrence said.

GridEx III featured the first use of social media for communications purposes. The report also recommended lengthening the planning time for the next exercise.

April 4, 2016

ISO-NE Again Defends Capacity Auctions

By William Opalka

ISO-NE CEO Gordon van Welie last week again defended the RTO’s capacity auction to congressmen who say market practices have led to inflated electricity rates for New England ratepayers.

In an eight-page, single-spaced letter sent Monday, van Welie reminded the New England congressional delegation of his testimony three years ago that highlighted the dramatic shift in the region’s market.

“Since then, 4,200 MW of resources have either announced plans to retire or have actually retired. Importantly, since 2013, the region’s Forward Capacity Market (FCM) has procured over 4,700 MW of new capacity resources — demonstrating that the FCM is procuring new, economically competitive resources to meet the region’s energy needs,” he wrote. (See Prices Down 26% in ISO-NE Capacity Auction.)

Van Welie’s letter was a response to a March 14 letter sent to FERC and the RTO by the delegation members after results of the 10th Forward Capacity Auction were filed.

“While these clearing prices were the result of a ‘competitive auction’ according to ISO-NE, the results are roughly equal to FCA 8, an auction that triggered administrative pricing rules due to lack of competition. They are also triple the capacity payments derived from the auctions prior to FCA 8,” the delegation wrote.

The congressmen acknowledged that prices declined more than 25% from FCA 9, but they noted that the previous year was a record $4 billion.

Ten senators and representatives joined in the letter, which was written by Massachusetts Democrats Rep. Joseph P. Kennedy III and Sen. Edward Markey. The members have repeatedly complained to FERC, without success, about alleged market manipulation. (See Congressional Meeting Fails to Sway LaFleur on Capacity Results.)

Van Welie said that market participants respond to price signals.

“We share your goal of ensuring that prices in the capacity market are just and reasonable. The FCM must and does signal the true value of capacity in New England. Artificial prices (whether too high or too low) do not benefit regional electric reliability or New England residents,” he wrote.

April 4, 2016

ERCOT Stakeholders Agree on Lost Opportunity Costs Rule

By Tom Kleckner

AUSTIN, Texas — ERCOT’s Technical Advisory Committee last week agreed on a method for paying lost opportunity costs to generators ordered to ramp down for grid reliability, a solution that will now go to the ISO’s Board of Directors.

Stakeholders discussed three options brought forth by ERCOT staff to address Nodal Protocol Revision Request 649 (Addressing Issues Surrounding High Dispatch Limit (HDL) Overrides), which was remanded back to TAC during the board’s February meeting. (See LOC Rule Sent Back to ERCOT’s Stakeholder Process.)

Staff’s preferred option was the first of three it presented: rewriting the NPRR’s language to replace compensation for opportunity costs with “justified” losses suffered by qualified scheduling entities (QSEs) holding existing contracts. The QSEs would have to provide an attestation of loss, calculations and supporting documentation to recover a claim.

A second option proposed software changes to override the resource node’s LMP, which would have created difficulties at the 98 nodes with at least two generator connections. The third, and priciest option, at $200,000 to $300,000 plus ongoing support, would pre-position manual constraints associated with each resource node in the system model.

As the discussion wore on, it became apparent stakeholders were coalescing on the first of ERCOT’s options.

“This seems to be a quickly diminishing issue,” said Shell Energy’s Greg Thurnher, representing independent power marketers. “It looks like Option 1 is the remedy.”

Brandon-Whittle,-Megawatt-Analytics-web — Whittle

“We think Option 1 is the way to go for now,” said Megawatt Analytics’ Brandon Whittle, speaking for Odessa-Ector Power Partners and Koch Services. “It puts the onus on the people who might get hurt. No generator wants to be paid back for their losses because of HDL overrides. We’d rather adjust the LMPs.”

The proposal passed by a 23-5 vote, with two abstentions. The NPRR will go before ERCOT’s board April 19. Staff will revise the revision request’s impact analysis and better define energy bilateral contracts.

Odessa-Ector, a subsidiary of Koch Ag & Energy Solutions, initiated discussion of the issue when it claimed its combined cycle plant had lost $300,000 because of three days of dispatch overrides in November 2012. ERCOT submitted the NPRR to satisfy a settlement agreement with Odessa-Ector after the company filed a complaint with the Public Utility Commission of Texas (docket #41790).

Luminant’s Amanda Frazier expressed a preference for an earlier version of the NPRR, which failed to secure sufficient votes. But she said that in subsequent discussions, “ERCOT has eliminated a number of concerns we originally had.

“The damages are limited to those attested to by the resources, and compensating the actual damages rather than the opportunity costs is a good compromise,” she said.

Resmi Surendran, ERCOT senior manager of market analytics and design, highlighted staff’s efforts to reduce HDL overrides, which peaked at more than 348,000 minutes in 2011. The numbers have steadily dropped since then, with only 57 minutes of overrides recorded last year.

Surendran attributed the improved results to increased operator training, their ability to enter manual constraints, the availability of new generic transmission constraints and topology improvements.

Whittle sought reassurance from ERCOT that the NPRR’s cost can be reduced from its current staff estimate of $100,000 to $150,000.

“We try to implement [any changes] at the minimum cost we can,” said Kenan Ögelman, ERCOT’s vice president of commercial operations. “We’ll definitely go back and see if we can’t reduce the cost. I just can’t give you a number, right now.”