Page 1450 – RTO Insider

April 11, 2016

Eversource CEO Retiring; CFO Named Replacement

By William Opalka

Eversource Energy CEO Tom May will retire in a month and be replaced by current CFO Jim Judge, the company announced Wednesday.

May, 68, will become board chairman after the company’s annual shareholders meeting May 4 in Boston. Under the succession plan, Judge will join the board next month and become chairman at Eversource’s annual meeting in 2017.

James J Judge Eversource Energy 2016 — Judge

May and Judge have worked together for 38 years. For the past 22 years, before and during a series of mergers, May has been CEO of Boston Edison, NSTAR and Northeast Utilities, which was renamed Eversource Energy in 2015. (See Northeast Utilities Rebranding as Eversource Energy.)

NSTAR and Northeast Utilities merged in 2012 to create an electric and gas utility company in Connecticut, Massachusetts and New Hampshire with 3.6 million customers and a market capitalization of $18 billion. The company has joint headquarters in Boston and Hartford.

“Tom May has been an extraordinary leader for more than two decades as chief executive. He has delivered superior results in every category — customer, financial, operations, safety and community,” Sanford Cloud, lead trustee of the board, said in a statement.

Judge will remain in his role as Eversource CFO until a successor is named.

Besides pursuing growth and acquisitions, May has become known for forging partnerships with developers to propose controversial projects that would bring fuel resources into New England.

In 2008, NSTAR and Northeast Utilities formed a joint venture, Northern Pass Transmission, to import Canadian hydropower supplied by Hydro-Quebec through New Hampshire. That project, vehemently opposed by some environmentalists and natural gas generators, is currently undergoing site evaluation by state officials. (See Committee Rules Northern Pass Application Complete.)

Eversource also has a 40% stake in the proposed $3 billion Access Northeast natural gas pipeline with partners Spectra Energy and National Grid. The pipeline would run through New York, Connecticut, Rhode Island and Massachusetts. (See Algonquin Submits Pre-Filing Request for Access Northeast Pipeline.)

Pipeline plans have generated controversy as some state regulators have endorsed a regional plan to have funding come from electricity customers. (See Massachusetts Regulators Endorse Pipeline Contracts.)

April 11, 2016

Dominion: Tx Project Should be Regionally Allocated

By Suzanne Herel

Dominion Resources is asking FERC to rehear two related February decisions in which the commission reversed a previous order and ruled that transmission projects that solely address a transmission owner’s local planning criteria are not eligible for regional cost allocation (ER15-1387).

In its first application of the rule, FERC said Dominion was solely responsible for the cost of its $160 million, 500-kV Cunningham-Elmont rebuild (ER15-1344). (See FERC Does 180 on Local Tx Cost Allocation in PJM.)

Dominion also has filed a protest of PJM’s compliance filing, which FERC required in its February determination.

The company requested that FERC rule on the rehearing request at the same time it decides on PJM’s compliance filing.

Also asking for rehearing are Old Dominion Electric Cooperative, LSP Transmission Holdings and ITC Mid-Atlantic Development.

Meanwhile, PJM requested a clarification on how it should apply the new methodology to certain projects in its Regional Transmission Expansion Plan.

In its rehearing request, Dominion argued that its proposal has regional benefits and is unlike 98% of Form 715 projects whose costs are designated to the local TO because they deliver only local benefits.

“The other 2% have had their costs allocated at least 50% regionally because they belong to a cost allocation class previously determined to have regional benefits,” it said. “Nothing about the 98% statistic explains why such projects no longer have regional benefits.”

April 11, 2016

Wabash Valley Acquires Struggling Peabody Energy’s Share in Prairie State

By Amanda Durish Cook

FERC last week approved Wabash Valley Power Association’s acquisition of a 5% interest in two 800-MW coal-fired units at the Prairie State Energy Campus for $57 million — less than a quarter of what seller Peabody Energy paid (EC16-62).

Wabash Valley - Peabody Energy - Prairie State Energy Campus — Prairie State Energy Campus *Source: Peabody Energy*

Wabash Valley, an Indianapolis-based generation and transmission cooperative, said the transaction will add 83 MW to its 1,105 MW of generation capacity, most of which is in MISO.

Peabody Energy, which had paid $246 million for its share in Prairie State, agreed to sell to Wabash Valley following a competitive bidding process, part of a restructuring that has resulted in the sales of almost $500 million in assets since last year. Nevertheless, Peabody, the world’s largest private-sector coal company, said last month it may have to file for bankruptcy protection because of its inability to meet debt payments.

The city of Martinsville, Va., a customer of American Municipal Power, which has a 23% interest in Prairie State, filed a comment expressing concern that the sale would diminish the value of the southwestern Illinois facility and result in increased rates for its customers. The city said the sale price values the facility at about 80% less than the indebtedness for which the communities are liable under their power sales agreements.

The commission declined Martinsville’s request to conduct an inquiry into whether the sale would create a hardship for the communities paying debt service, saying it was outside the scope of its merger review authority. In addition, the commission said that the commenters “fail to explain [how the sale] might result in increased rates for wholesale customers.”

April 11, 2016

PJM Market Implementation Committee Briefs

VALLEY FORGE, Pa. — PJM moved the day-ahead energy market offer deadline to 10:30 a.m. from noon without incident April 1, PJM’s Adam Keech told the Market Implementation Committee Wednesday.

“We didn’t have many people complaining, ‘We missed the window,’” he said.

Offers were cleared in 2.5 hours on average, within the desired three-hour window. It helped that the system load was light, he said.

Commented Independent Market Monitor Joe Bowring: “We did notice that the liquidity of the gas market had not shifted to earlier in the morning just yet.”

But when he asked members if anyone else had observed the same, no one spoke up.

The scheduling change aims to better align the gas and electric markets. (See PJM Moving on Day-Ahead Schedule Changes.)

Members Endorse New Way to Measure Emergency DR

Members unanimously endorsed changes in how demand response is measured and verified in emergency situations.

Existing procedures, which use the hour before an event as the default customer baseline (CBL), can be inaccurate in the early morning or on days with multiple dispatches, PJM’s Pete Langbein said. It also can require a cumbersome administrative review process.

The new method changes the emergency energy default CBL from the hour before to the current default economic CBL.

It also eliminates the ability to create an economic registration after the fact and use the CBL to settle the event.

The new process is expected to measure energy load reduction more accurately and be consistent with the calculation of non-summer compliance under the new Capacity Performance model.

The changes were ready to be implemented in 2014, but PJM held off until the Supreme Court ruled that DR would remain in the energy market. (See Supreme Court Upholds FERC Jurisdiction over DR.)

Allocating Spot-in Service for NYISO Imports to be Studied

With seven abstentions, the committee approved a problem statement and issue charge to study how to improve the process of allocating spot-in transmission for energy imports from NYISO.

Vitol’s Joe Wadsworth, who presented the proposal, said the timing of the markets and the first-come-first-serve method of reserving spot-in transmission make it difficult for participants to efficiently schedule such imports.

PJM opens the window to reserving next-day spot-in service at 9 a.m., but NYISO doesn’t release its day-ahead market results until at least 9:35 a.m. and sometimes as late as 11 a.m., Wadsworth said.

Thus, participants who use spot-in transmission to compete on near-term import supply opportunities at the seam may have to reserve the service before they find out what has cleared in NYISO, he said.

Spot-in is free but limited in quantity, and there is no priority for participants who have cleared the NYISO market.

“If you can’t get spot-in transmission for your imports, then your day-ahead transactions can be curtailed, and suddenly you may have exposure to real-time prices,” he said.

Work on the issue is expected to take six to nine months.

No one voiced similar concerns with MISO at the meeting.

Changes to Emergency Procedures Tool Coming in May

Members received an update on PJM’s emergency procedures, which are changing because of the June 1 implementation of Capacity Performance.

Initial adjustments will be visible in the online emergency procedures tool on May 5 so they may be used for the summer emergency procedures drill, which is scheduled for May 10.

More changes will come on May 26. They include new fields, tabs, timestamps and flags giving members information on performance assessment hours.

Also new is a “deploy all resources” action for emergency events that occur without warning as opposed to evolving over time. The purpose of the action is to instruct members to dispatch all generation resources and implement load reductions immediately.

24-hour Max Run Time Parameter Set for June 1

PJM intends to implement a maximum run time parameter value of 24 hours June 1 for all generation resources except for pumped hydro power and market sellers who believe their resource cannot meet that value.

Documentation to that effect must be submitted to unitspecificpls@pjm.com by April 20.

Supporting documents must include original equipment manufacturer specifications of unit constraints.

Max run time values will be issued by May 15.

Settlement C Discussion Terminated

Members voted to approve the Market Settlement Subcommittee’s request to stop work on establishing a “Settlement C” method that would allow electricity distribution companies to resolve billing errors beyond the 60-day Settlement B time frame.

The group had been working on the issue since September.

In a subcommittee poll of 22 responders representing 119 participants, 40% voted to continue to develop a solution, while the rest chose maintaining the status quo. At the MIC, 64% voted to kill the initiative.

PJM Proposes Clarifications to Bilateral Transactions

PJM proposed revised rules regarding bilateral capacity transactions that would maintain the physical nature of the deals to ensure members’ indemnification.

In such transactions, a seller transfers capacity to a buyer but retains the obligation for performance. (See “PJM Proposes Clarifications to Capacity Bilateral Transactions,” PJM Market Implementation Committee Briefs.)

The proposal assigns bonus payments to the buyer in proportion to the megawatts transacted. It also requires that any replacement transactions entered into by the seller be traceable. Therefore, this would not be able to be done in an incremental auction.

“If they went into an incremental auction to do this, all the parties would lose the visibility of who now is [providing the capacity that was] originally part of the bilateral,” Assistant General Counsel Jen Tribulski said. “We thought that these transactions would be best served if the seller was able to replace them, but not by an incremental auction.”

The clarifications will require a Tariff change.

— Suzanne Herel

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