Page 1293 – RTO Insider

April 25, 2017

SPP Regional State Committee Briefs

SPP’s Regional State Committee last week approved doubling the timeframe for conducting regional cost allocation reviews (RCARs), leaving only approval from the Board of Directors this week before the change becomes official.

Staff had been conducting RCARs every three years. With board approval of the recommendation and accompanying revision request (TRR-223), those reviews will now be conducted every six years.

The Market and Operations Policy Committee earlier approved the same recommendation from the Regional Allocation Review Task Force, which said the change would save SPP manpower and consulting costs. (See “Cost Allocation Review Cycle Could Extend to 6 Years,” SPP Markets and Operations Policy Committee Briefs.)

The most recent review, RCAR II, showed more positive benefit-to-cost ratios and only one deficient transmission zone, which already has a project in the 2017 Integrated Transmission Planning assessment. SPP said it took about 2,100 staff hours and more than $417,000 in payments to outside consultants to complete the review. The first RCAR incurred a similar expense.

“It’s a really elegant solution, because it takes a tremendous amount of staff’s time,” said Donna Nelson, chair of the Public Utility Commission of Texas. “It’s a heavy lift. All of the commissioners here have been very respectful of each other, with respect to the cost-benefit analysis.”

South Dakota Public Utilities Commissioner Kristie Fiegen isn’t so sure. “I believe we could be locking in winners or losers for an extended period of time,” she said. “It concerns me we’re moving the cost allocation review out six years, but I certainly appreciate the group looking at the cost of the study. The cost-benefit ratio is extremely important to our stakeholders.”

Patrick Lyons, chair of the New Mexico Public Regulation Commission, advocated for a four-year delay between reviews, but none of the other committee members backed his proposal.

Staff pointed out that any member that feels it has an imbalanced cost allocation can request relief through the MOPC. It also said it was trying to improve the review process through the use of more accurate information.

“One thing staff is doing now is using real market data and running the market [model] without that transmission, then going back to Day 1 of the market to find the value of the transmission,” SPP General Counsel Paul Suskie said. “We’re looking at possible different ways to do the RCAR.”

Wise: Few Solutions to Wind-Energy Glut

Golden Spread Electric Cooperative’s Mike Wise told the committee that his Export Pricing Task Force did not have a “whole lot of solutions” for shipping SPP’s ample wind resources out of the footprint.

“We’re waiting on members and staff to bring ideas,” said Wise, who chairs the group and the Strategic Planning Committee. “There’s no stomach inside the task force or the SPC, that I’ve heard, that we want to build transmission to export wind and have the consumers in the footprint pay for it. I would encourage anyone who wants to come get the wind to build the transmission.”

The group has prioritized several market changes — such as ramp products and storage resources — to accommodate wind exports as staff time and dollars are available over the next few years. Wise said the group would continue meeting over the next few months as “opportunities” are brought forward.

SPP has more than 16 GW of installed and operational wind capacity, another 8 GW with signed generation interconnection agreements and a potential 43 GW overall.

The task force has begun to explore coordinated transaction scheduling, which allows for near real-time scheduling of power across RTO interfaces, based on the price spread between RTOs. (PJM has adopted CTS with NYISO and plans to launch with MISO this fall.)

“We really have to work with the other RTOs,” Wise said. “It’s not MISO that needs the power, it’s the other RTOs east of MISO.”

Committee Approves CAWG Recommendations

The RSC also approved several motions from the Cost Allocation Working Group, which reports up to the committee. The items were also approved by the MOPC earlier this month.

A recommendation to approve the Seams Projects Policy Paper as consistent with previous RSC actions. The paper sets guidelines for SPP approval and cost allocation processes for non-FERC Order 1000 interregional transmission projects on a project-by-project basis.
Another recommendation to approve regional funding for SPP’s portion of a transformer project and line uprate at an Associated Electric Cooperative Inc. substation near Springfield, Mo.
Approval of RTWG-RR208, which implements the Transmission Planning Improvement Task Force’s white paper for new regional planning processes by replacing current planning schedules with an annual transmission expansion plan, creating a standardized scope; establishing a common planning model for use across the various planning processes; and creating a staff/stakeholder accountability program.
Finding MRR203 consistent with respect to the allocation of financial transmission rights. The revision adds a “last-chance” second set of auction revenue rights nominations in the monthly ARR process, where any source-to-sink path can be nominated.
Finding RR202 also consistent with the RSC’s past policy decisions with in allocating FTRs. The change complies with FERC guidance on SPP’s disparate treatment of point-to-point and network integration transmission service (NITS) during re-dispatch. NITS would be eligible for ARR during limited times of the year and only for the service not subject to redispatch, but not for long-term congestion rights. (See SPP Hopes Congestion Rights Rule Change Wins FERC OK.)

– Tom Kleckner

April 25, 2017

MISO Planning Subcommittee Briefs

CARMEL, Ind. — MISO last week presented a strawman proposal for non-transmission alternatives that includes redispatch, load shed, reconfiguration and remedial action schemes.

The Planning Advisory Committee is currently working on Business Practices Manual 020, which outlines the process for considering non-transmission alternatives. (See “Rules on Non-Transmission Alternatives Ready for PAC Review,” MISO Planning Subcommittee Briefs.)

At the April 18 Planning Subcommittee meeting, MISO officials provided details of the alternatives:

The generation redispatch option would require an evaluation to “demonstrate that there are sufficient generation units that are available to provide the incremental capacity necessary to maintain loadings and voltages within applicable [ratings], without reliance on any single unit,” MISO proposed. The RTO said no more than 10 individual units or 1,000 MW will be used in any redispatch plan. Candidates for redispatch include all network resources and energy resources, and participating generators must have a distribution factor of greater than 3%. Before using a redispatch plan that requires decommitting a resource, the RTO said it will evaluate reliability and voltage without the unit. MISO will also exclude non-dispatchable units and nuclear generation from possible redispatch solutions.
Load shed will be allowed when local planning criteria permits, MISO said. The RTO committed to flagging constraints that result in load shed of 1,000 MW or more for potential physical upgrades.
System reconfiguration will be allowed as a corrective plan, MISO said, unless reconfiguration places noninterruptible load on a transmission radial “such that a single contingency would interrupt service to multiple customers, the reconfiguration results in opening of more than a single transmission line or the reconfiguration results in transmission flows to be routed through sub-transmission or distribution facilities.”

“All three of these come from current, real-time operating procedure,” engineer Patrick Jehring said.

Remedial action schemes will use language pulled directly from NERC, with existing schemes allowed as acceptable corrective action plans. New schemes will be evaluated on a case-by-case basis. The evaluation will include expected frequency of need for a RAS and comparison of costs to install and maintain it compared to the cost of a transmission upgrade. “Remedial actions schemes must be far cheaper than a new line,” Jehring said.

Jehring also said most of the strawman was borrowed from existing MISO standards, but that the RTO still wants stakeholder suggestions. He asked for written feedback by May 5.

“How much risk to the load-serving capability is acceptable on the planning horizon?” Jehring asked stakeholders.

In response, they expressed concerns in particular on load shedding as a non-transmission alternative option.

Consultant Roberto Paliza of Indianapolis said MISO should be transparent when it identifies specific solutions. Paliza added that too much load shed to resolve contingencies can cause a concern and could make transmission construction more appealing. Planning Subcommittee liaison Jeff Webb agreed. “If the solution is load shed, we should be explaining why that is acceptable,” Webb said.

NRG Energy’s Tia Elliott asked if MISO could gather all transmission owners’ individual load shed criteria and consolidate it into a single document. “It varies across the footprint from transmission owner to transmission owner,” she said. “Not understanding what those variables are makes it difficult for stakeholders to make an informed decision.”

Jehring said MISO already posts such planning criteria, though not consolidated, on its website.

MISO Unveils MTEP 17 Transfer Analysis

As part of its 2017 Transmission Expansion Plan, MISO outlined a proposed analysis on a half-dozen MISO transfers.

MISO planning subcommittee load shed — | *MISO*

This year, MISO is proposing to study transfers between MISO North and SPP; two transfers from Manitoba Hydro to MISO North; wind resources in Northern Illinois to Ohio (both PJM territories) using MISO transmission in Indiana; MISO North and Central to MISO East; MISO Central to the Tennessee Valley Authority; and MISO South to SPP.

Scott Goodwin, MISO transfer analysis engineer, asked for stakeholders to review the transfer selection.

This year, MTEP studies include the usual base reliability and economic studies along with a trio of specialized studies: the multiyear regional transmission overlay study, a generation retirement study and the footprint diversity study, which could identify an alternative to using SPP transmission for transfers between MISO North and MISO South. (See “Studies Could Assist in Relieving North-South Constraint,” MISO Planning Advisory Committee Briefs; “Generators Identified in MISO Retirement Analysis,” MISO Planning Subcommittee Briefs.)

MTEP 17’s scope will be finalized in December.

— Amanda Durish Cook

April 25, 2017

ISO-NE Study Projects Impact of $64/ton Carbon Price

By Michael Kuser

WESTBOROUGH, Mass. — A new analysis by ISO-NE shows that increasing carbon allowance prices from $24/short ton to $64/short ton would boost the region’s LMPs by more than 30% under all six scenarios studied.

The RTO added the new sensitivity in response to stakeholders who said the $24/short ton (2015 $) allowance price used in an earlier version of the 2016 Economic Study was too low to drive the investments needed to meet greenhouse gas reduction goals. The $64 figure is based on the federal government’s estimated social cost of carbon.

Michael Henderson, ISO-NE director of regional planning and coordination, presented the results of the revised study to the Planning Advisory Committee on April 19.

The Regional Greenhouse Gas Initiative emissions cap — 91 million short tons in 2014 — is set to drop by 2.5% annually through 2020. Some activists have called on RGGI to double the cuts to 5% per year. Most of the six scenarios studied failed to meet those targets.

carbon allowance prices iso-ne allowance study — | *ISO-NE*

Dan Pierpont, manager of external affairs for CPV Towantic, asked about the “pricing effects of RGGI goal-busting performance,” while an unidentified woman participant on the phone said she wanted “RGGI-threatening scenarios clearly delineated in the executive summary for state policymakers.”

New Names for Numbered Scenarios

In place of the six numbered scenarios in the earlier draft study, Henderson said, “we’ve given nicknames to the scenarios so they’ll be intuitively obvious.” The new names are:

RPS + Gas: Physically meet renewable portfolio standards and replace generator retirements with natural gas (combined cycle units). It fails to meet the RGGI targets regardless of whether transmission constraints are modeled or not.
ISO Queue: Physically meet RPS and replace generator retirements with new renewable/clean energy. It meets the 5% RGGI reduction only in the transmission-unconstrained model and then only using the $64/ton carbon adder.
Renewables Plus: Physically meet RPS; add renewable/clean energy, energy efficiency, solar PV, plug-in electric vehicles and storage; and retire old generating units. It meets the RGGI targets under all sensitivities.
No Retirements (beyond Forward Capacity Auction 10): Meet RPS with resources under development and use RPS alternative compliance payments (ACPs) for shortfalls; add natural gas units. It fails to meet the RGGI targets under all sensitivities. It shows the highest LMPs assuming a $64/ton carbon price, averaging $69.70/MWh including transmission constraints.
Gas + ACPs: Meet RPS with resources under development and use ACP, and replace retirements with natural gas. It does not meet the RGGI targets under any sensitivity. It shows the highest LMPs under a $24/ton sensitivity, at $52.63 (transmission constrained).
RPS + Geodiverse Renewables: Scenario 2 with a more geographically balanced mix of on/offshore wind and solar PV. It meets the RGGI targets under the $64/ton sensitivity but fails under the $24/ton transmission-constrained model. It had the lowest LMPs of all six scenarios under all sensitivities, averaging $34.12/MWh ($24/ton) and $44.21/MWh ($64/ton) with transmission constraints modeled.

“Clearly, scenarios with the heavier renewable elements, scenarios 3, 6 and 2, show the lowest CO₂ emissions,” Henderson said. “As far as load-serving entities go, there is no change in the scenario order: The least expensive remains least, and the most expensive remains most.”

Scenario 2 shows the biggest decrease in LMPs when transmission constraints are relieved, a difference of almost $22/MWh assuming $64/ton carbon.

LMPs for scenarios 4 and 5 show virtually no change with the transmission constraints modeled because they have little congestion, Henderson said.

25-MW Threshold

Henderson noted that the study applies carbon allowance prices to all generating units in New England — including those below the 25-MW threshold employed by RGGI.

Ignoring the carbon prices for smaller units could actually increase emissions, Henderson said, because high emitting small units, such as biomass, would be dispatched more often.

“The new methodology is important, for when you raise carbon prices — if you do nothing to affect the resource dispatch order — you have no effect on emissions,” Henderson said. “As the resource mix changes and you end up with a greater amount of zero-emission resources, overall emissions decrease.”

The completed study is “on track” for publication in the second quarter, and a natural gas analysis will be announced at the May or June PAC, he said.

Study of Other Options Requested

David Ismay, senior attorney for the Conservation Law Foundation, gave a presentation asking the RTO to develop and price at least two new scenarios for generation and transmission that could reduce emissions to or below the levels of Scenario 3 at a lower cost.

“By developing a range of least-cost options for such public policy-compliant futures, the result of a Least-Cost, Emissions-Compliant System Topologies Study could be used to test the ability of market reforms to deliver the desired results of the market-policy integration that is the goal of both the on-going [New England Power Pool] Integrating Markets and Public Policy (IMAPP) effort as well as FERC’s recently opened Docket No. AD17-11,” Ismay said in a letter to Henderson.

Henderson replied that the RTO “requires specificity in any suggested economic study and will not invent a new system.”

Doug Hurley of Synapse Energy Economics offered to help Ismay and the CLF develop the right metrics for their request. Other participants spoke up to support Ismay’s use of the PAC forum to address his and the foundation’s concerns.

April 25, 2017

Spring Oversupply Lifts CAISO Curtailments

By Robert Mullin

CAISO is curtailing an increasing volume of renewable generation this spring as the ISO sees its “duck curve” already dipping to levels not forecast to occur until 2021.

Compounding the issue is an unusually high snowpack coming after years of drought that had previously undercut California’s hydroelectric output, making more room for solar.

CAISO duck curve curtailments — Recent events have put CAISO “net load” effectively off the original “Duck Curve” chart, with load served by dispatchable resources falling to levels not forecast to occur until 2021. | *CAISO*

“Everything’s kind of playing out the way we had expected, maybe just a little bit faster,” Mark Rothleder, the ISO’s vice president for market quality and renewable integration, said during an April 19 meeting of the Energy Imbalance Market (EIM) Governing Body.

All-Time Low

“We’ve seen net load levels of 10,386 MW” — an all-time low, Rothleder said. “This is about four years ahead of the schedule of where we expected to be” when the ISO first introduced the duck curve in 2013.

“Net load” represents system load minus the combined output from utility-scale wind and solar resources. The ISO cares about those three components because they all represent variable factors, Rothleder explained. Where system operators once had to track and balance only load, they must now deploy dispatchable resources to balance whatever portion of the load is not being served by renewables.

The all-time-low net load figure cited by Rothleder occurred on April 9. It was also off the charts of the original graph, which only forecasted out to 2021 (see graph).

“When we put the duck out a few years ago, we probably didn’t factor in the effects of behind-the-meter solar as much as we’re actually seeing play out,” Rothleder said.

CAISO estimates that its balancing authority area contains about 5,000 MW of rooftop solar capacity, which reduces system load during daylight hours.

Rothleder pointed out that the duck curve is also intended to illustrate the sharp daily ramps needed from dispatchable resources as solar output starts to wane as residential load ticks upward in the evening. In December, the ISO observed a 13,000-MW three-hour ramp about four years ahead of expectations.

Deeper, Longer, Steeper

“Looking forward, we should continue to expect that the belly of the duck is going to get deeper and that the evening ramps will get longer and steeper as well,” Rothleder said.

At about 11,000 MW of net load, the ISO has “to start stacking up what other supply is already on the system that you can’t move,” Rothleder explained. In California, that means about 2,000 MW of nuclear, 1,000 MW of qualifying facilities under the Public Utility Regulatory Policies Act and — “in a good year” — around 6,000 MW of hydroelectric output.

With snowpack levels in the Sierra Nevada mountains currently at about 180% of normal, and California’s drought officially declared over, this is a very good year for hydro.

In leaner times, the steady growth of California’s solar capacity conveniently substituted for the decline in hydro, Rothleder said. Now the two must compete, with hydro curtailments limited by flood control needs and environmental restrictions on spilling water over dams.

“You’re now getting into a condition where you have an excess amount of energy and you have to do something with it,” Rothleder said.

One key response has been exporting to neighboring BAAs through the EIM, which last month helped the ISO avoid more than 100 GWh of renewable curtailments.

“And if we run out of that ability, we effectively get to the point where we have to curtail, whether it be economic curtailment through bids on the wind and solar resources to dispatch down, or manual curtailment because we ran out of bids,” he said.

80 GWh Curtailed in March

CAISO curtailed about 80 GWh of renewable generation in March, nearly double the curtailments during the same month last year. So far this year, curtailments have occurred in 31% of all five-minute dispatch intervals, compared with 21% last year and 16% in 2015, the ISO estimates.

EIM Governing Body member Valerie Fong asked how the curtailments were allocated across the ISO’s market.

“It’s not an allocation,” Rothleder replied. Rather, resources are curtailed based on what price they offer into the market. Renewable resources frequently bid in at negative prices because of other compensation derived from renewable energy certificates and tax credits.

“The one that’s bidding -$15 will be dispatched down first before [a resource bidding] -$30,” Rothleder said.

Is Storage an Answer?

Body Chair Kristine Schmidt asked whether there were any developments related to energy storage that could help reduce curtailments.

Rothleder said “the proposition of storage is an ongoing question” in which CAISO market participants must determine when curtailments reach a level that warrants investment in “higher-cost” storage solutions.

“When does that threshold get crossed? I don’t think we’re there at the current levels” of curtailments, Rothleder said.

Sara Edmonds, general counsel with PacifiCorp Transmission, pointed out that the ISO’s own numbers show that curtailment avoidance through the EIM this year is lower than last (see graph).

“I’m still trying to understand that myself,” Rothleder said. “There could be various reasons.”

One potential reason is that supply conditions across the West are different from previous years, with snowpack high in other regions as well.

A second possibility: EIM participants could be changing the way they deploy resources, reducing the potential for downward dispatch in their own balancing areas.

A third: The inclusion of Arizona Public Service and Puget Sound Energy in the EIM last October could be altering the dynamic of the market.

“So I don’t have the full explanation,” Rothleder said. “I think we’ll see how things continue to play out over the rest of the spring and summer — and especially with other hydro conditions throughout the West.”

April 24, 2017

Court Rebuffs New England TOs, Upholds FERC ROFR Order

By Michael Kuser

The D.C. Circuit Court of Appeals last week rejected challenges to FERC Order 1000 by New England Transmission Owners and state officials (15-1139).

The TOs had challenged FERC’s March 2015 ruling on ISO-NE’s Order 1000 compliance filing, in which the commission ordered the removal of the right of first refusal in the Transmission Operating Agreement among ISO-NE and the TOs (ER13-193, ER13-196). Emera Maine acted as lead petitioner, with independent transmission developer LS Power Transmission opposing the TOs as lead intervenor.

E Barrett Prettyman D.C. Circuit Courthouse

The second part of the ruling rejected a petition by the state officials complaining that FERC’s ISO-NE compliance order violated state sovereignty.

TOs’ Challenge

The TOs asserted that FERC’s orders were inconsistent with its past decisions, that the commission applied the wrong legal standard for measuring whether the Mobile-Sierra presumption had been overcome, and that the commission ignored the evidence before it.

The April 18 ruling by a three-judge panel, authored by Judge Robert L. Wilkins, disagreed with the TOs on both counts.

The court rejected what it termed the TOs’ “invitation to don blinders” in making a narrow interpretation of Mobile-Sierra, which requires the commission to “presume a contract rate for wholesale energy is just and reasonable,” prohibiting it from rejecting the contract unless it finds that the rate “seriously harm[s] the public interest.”

It also dismissed the TOs’ contentions that the commission identified no evidence to support its conclusion that the ROFR harmed the public interest by inhibiting transmission development and that it ignored the contrary evidence submitted by ROFR defenders.

The TOs introduced evidence that ISO-NE had placed $4.7 billion in new transmission facilities in service and had another $5.7 billion in projects in development. That, the TOs said, proved that the ROFR did not harm the public interest.

The court said the TOs based their argument “on the faulty premise that economic theory cannot provide the basis for FERC’s decisions.”

The commission confronted the evidence of transmission development “head-on,” the court said. The commission said the ROFR “continues to threaten the public interest by avoiding expected efficiencies and cost savings and makes the need to foster competitive practices more acute.”

The court said the commission explicitly rejected the inference that “the incumbent transmission owners are sufficiently developing projects under the existing framework with their current rights of first refusal.” While the TOs’ claim of a functioning market with the ROFR “may be plausible,” the contrary conclusion drawn by the commission is also plausible, the judges said.

“Where the evidence might support more than one rational interpretation, ‘the question we must answer … is not whether record evidence supports [the petitioner’s] version of events, but whether it supports FERC’s,’” the court ruled.

NESCOE Ruling

The second part of the ruling rejected a petition by the New England States Committee on Electricity and agencies from five of the six states it represents: Connecticut, Massachusetts, New Hampshire, Rhode Island and Vermont. The state petitioners claimed that in its ISO-NE compliance order, the commission went beyond Order 1000 and “impermissibly altered the balance of responsibility and power as between state governments and ISO-NE.”

The five states insisted that Order 1000 requires not only a process to identify transmission needs driven by public policy requirements and evaluate potential transmission solutions that could meet those needs, but also selection of whichever project is the most efficient or cost-effective. They also contended that the Federal Power Act does not grant FERC authority over “the means by which states meet their own public policy mandates.”

The court rejected the argument as an objection to Order 1000’s entire regional planning and cost allocation scheme, which assigns ISO-NE the role of planning for the region’s transmission needs.

“Order No. 1000 established a regional planning process that is agnostic as to the provenance of the transmission needs, whether resulting from population growth or federal public policy or state public policy,” the ruling said. “The division of roles between ISO-NE and the states poses no jurisdictional problem for FERC. ISO-NE has no role in setting public policy for the states. ISO-NE considers transmission needs that arise from a variety of sources, one of which is the public policy requirements chosen by federal and state officials.”

The court said the states misread the word “select” in Order 1000.

The commission said Order 1000 and subsequent rehearing orders were intended to clarify which entity must control each step of the process and that there is no requirement that ISO-NE “must select … a transmission solution to address every identified transmission need driven by a public policy requirement.”

If a solution is selected, however, FERC said it “must be selected by ISO-NE rather than by NESCOE.”

“In light of these clarifications by the commission,” the court concluded, “there is no inconsistency with Order No. 1000.”

‘Off Ramp’

NESCOE General Counsel Jason Marshall found some solace in the adverse ruling. “While the court denied our petition, its ruling provides an interpretation that we have long sought: that ISO New England is not required to select a policy-driven project as part of the Order 1000 process,” he said in a statement. “This is an important potential ‘off ramp’ and clarification, which helps to prevent costly projects from being selected for development that states do not view as advancing their policies or that are not in the interest of consumers.

“We are still reviewing the court’s ruling and have not made a determination at this point regarding further review,” he added.

April 24, 2017

OMS May Add Voice to Pseudo-Tie Fracas

By Amanda Durish Cook

Organization of MISO States members will vote via email on whether to file comments in the Independent Market Monitor’s complaint over PJM’s pseudo-tie proposal (EL17-62).

At an OMS Board of Directors meeting April 20, staffer Marcus Hawkins said if the group agrees to file comments, the focus would be on MISO generators that pseudo-tie into PJM. The Monitor asked FERC on April 6 to eliminate pseudo-ties. (See Pseudo-Tie Feud Rises as Patton, NYISO Protest PJM Proposal.)

PJM OMS MISO pseudo-tie — OMS Meeting in February 2017 | © *RTO Insider*

The OMS Seams Working Group has been discussing the filling with Monitor David Patton, Hawkins said, and the group could draft comments by this week. If approved by members, the comments by the working group would be edited by the board before they are filed at FERC in early May.

“Right now, it looks like the group is leaning towards supporting some of the issues Dr. Patton has raised in his complaint,” Hawkins said.

Closed Session Procedure Outlined

OMS members have drafted a procedure for entering closed sessions during public meetings.

Sam Mabry of the Mississippi Public Utilities Staff said OMS’s governance group has suggested that notification of closed session requests be circulated a few days before the meeting with an explanation of the need. If an objection is raised, the OMS Executive Committee would decide by simple majority if the topic deserves a closed session, OMS members decided.

OMS MISO PJM pseudo-tie — Weber | © *RTO Insider*

OMS President and Indiana Utility Regulatory Commissioner Angela Weber said the new notice system need not be used to discuss personnel matters and commercially sensitive materials, which are already closed session matters per organization bylaws. Weber also agreed that closed sessions should extend to discussions covered by attorney-client privilege after Texas Public Utility Commissioner Ken Anderson raised the issue.

David Carr of the Mississippi Public Service Commission pointed out that OMS bylaws state that such information “may” be covered in closed session, so even those topics do not require closed sessions in all cases.

Weber said OMS is only looking to clear up when a closed session is used to discuss “gray matters.”

“I was uncomfortable with motions [for closed session] during meetings,” Weber explained.

Weber raised the need for a more specific closed session procedure after expressing concern in February that OMS used closed sessions too liberally to discuss FERC filings. (See Commissioners Ask MISO to Share Tx Project Cost Data.)

April 24, 2017

MISO Planners Looking at 3 La. Projects, Overlay ‘Skeleton’

By Amanda Durish Cook

CARMEL, Ind. — MISO transmission planners last week outlined three possible congestion-busting projects in Louisiana and a “skeleton” of potential projects from a long-term overlay study.

The overlay study, which used the MISO Transmission Expansion Plan 2017 futures, is designed to identify long-term transmission needs under a shifting resource mix, including possible paths for a line to link MISO South and MISO Midwest.

MISO overlay study MTEP 18 futures — | *MISO*

Preliminary results using an existing fleet projection show several 345-kV line additions in MISO Midwest, a handful of 500-KV lines in — and one leading into — MISO South, and a couple of new 230-kV lines in the Dakotas. (See MISO Begins 3-Year Tx Overlay Study.)

The policy regulations future shows a few of the 230- and 500-kV lines in the existing fleet future swapped for 345-kV ratings. The accelerated alternative technologies future depicts a large network of 765-kV lines in Central, including two 765-kV paths connecting South, and a direct current line across North Dakota and Minnesota in addition to the proliferation of 345-kV lines in Midwest and 500-kV lines in South.

MISO cautioned that “no conclusion has been reached on whether or how many projects may ultimately be recommended by the 2019 targeted completion date.”

Some stakeholders asked why MISO created preliminary overlays using MTEP 17 at all, when MTEP 18 futures consensus is close. Lynn Hecker, manager of expansion planning, said the RTO will begin examining MTEP 18’s distributed and emerging technology and see if the fourth future’s assumptions suggest the need for additional projects.

Louisiana Projects

Meanwhile, the RTO’s MTEP 17 Market Congestion Planning has produced three possible projects in MISO South: one market efficiency project and two economic projects.

All three project candidates are near the West of the Atchafalaya Basin (WOTAB) load pocket in southwest Louisiana and MISO’s control area in eastern Texas. No other areas in the RTO’s South met the RTO’s criteria for a possible project; the annual congestion planning study focused exclusively on South this year.

The projects are:

A new $122.7 million, 500-kV line from Hartburg to Sabine in southeastern Texas with a 500-kV substation and new 500/230-kV transformer at Sabine. The lone market efficiency project candidate has a 1.28 benefit-to-cost ratio;
A $2.8 million uprate of the Sam Rayburn-Fort Creek-Turkey Creek-Doucett 138-kV line in southeastern Texas with a 7.45 B/C ratio; and
A half-million-dollar upgrade of terminal equipment at southwestern Louisiana’s Carlyss substation that would increase the current 230/138-kV autotransformer capacity to 300 MVA at a 15.97 B/C ratio.

Arash Ghodsian, MISO manager of economic studies, said project candidates should be finalized by July.

Footprint Diversity Study

On the other hand, the RTO’s footprint diversity study, specifically designed to identify transmission for transfers between MISO Midwest and MISO South, will spend extra time in the suggestion-gathering step.

Ghodsian said 26 of the 32 stakeholder-submitted ideas involved connecting South and Midwest through coordination with neighboring regions.

He said MISO is seeking more projects that it can implement alone, asking stakeholders to focus only on suggestions that would connect one substation to another.

“Maybe let’s take it a notch higher and look for more technical discussion,” Ghodsian said.

MTEP 18 Futures

MISO said the four MTEP 18 futures generally received stakeholder support.

The RTO revealed proposed futures in early April, introducing a distributed and emerging technology 15-year future that captures more localized siting and storage. (See MISO Introduces Distributed Energy Future for 2018 Tx Planning.)

MISO has not studied anything like this future before. It envisions new renewables largely serving their local resource zones while rising storage capability — hitting 2 GW by 2032 — is placed near buses and two-thirds of all solar additions are distributed energy resources. The RTO usually assumes one-third of all new solar additions are distributed for planning purposes.

Policy studies engineer Matt Ellis admitted that the RTO isn’t modeling all combinations of possibilities and said nine stakeholders submitted about 13 suggested futures themselves, but he added that MISO’s proposed four futures “capture the highest and lowest bookends” and said stakeholders have indicated support.

“We do agree with stakeholders that we’re not studying all combinations, but we want this to be feasible. How many can we actually study and do the in-depth sensitivities on?” he said at the April 19 Planning Advisory Committee meeting.

Stakeholders also asked if MISO would change any of its nuclear assumptions given the recent bankruptcy filing by Westinghouse Electric, which has threatened the completion of new nuclear plants in Georgia and South Carolina. All MTEP 18 futures assume zero nuclear retirements.

“All [existing nuclear plants] have licenses through the study period. So that’s where we landed at, but we’re open to revising that,” Ellis said.

MISO will hold a more in-depth conversation at the July PAC meeting, he said.

April 24, 2017

NYPSC Order Seeks to Refine, Standardize DR Programs

By Michael Kuser

The New York Public Service Commission voted Thursday to maintain current incentive payment rates for utilities’ dynamic load management (DLM) programs through 2017 while ordering the companies to standardize their enrollment processes and approving other changes that the commission said would “ease DLM program enrollment and participation.”

incentive payment rates NYPSC — | *NYISO*

Approved in 2014, New York’s DLM initiatives include:

A peak load-shaving commercial system relief program (CSRP), which is called 21 hours in advance of a need for load relief, as determined by day-ahead load forecasts;
A distribution load relief program (DLRP) to support local reliability, called two hours in advance during contingencies and system emergencies; and
A direct load control (DLC) program, which allows utilities to cycle residential and small commercial customers’ air conditioning and other controllable loads.

In their December 2016 annual reports on the programs, Central Hudson Gas & Electric, Niagara Mohawk Power and Orange and Rockland Utilities proposed changes. New York State Electric and Gas and Rochester Gas and Electric did not seek changes.

Before calling a vote on the order, which was included in the consent agenda, Interim Commission Chair Gregg Sayres asked for any comments. Only one other commissioner remains on the PSC following the March resignation of Chairman Audrey Zibelman and the retirement of Commissioner Patricia Acampora: Commissioner Diane Burman, who spoke up.

She said she voted no on some aspects of the demand response cases last year out of “a concern that the commission take a more holistic approach.”

However, Burman said there was a need to act now to set the DR rules for the summer 2017 capability period, which runs from May 1 through Sept. 30. “There needs to be regulatory certainty,” she said. “If we delayed action here it could mean changes being made mid-period or not at all.”

Incentive Changes Deferred to 2018

While maintaining the current incentive payments for 2017, the commission said it will consider changes for 2018 based on the results of marginal cost of service (MCOS) studies and the Value of Distributed Energy Resources proceeding initiated in March. (See NYPSC Adopts ‘Value Stack’ Rate Structure for DER.)

“Avoided [transmission and distribution] infrastructure costs constitute the majority of the benefits applicable to DLM programs,” the commission said. “DLM program incentive payment rates are directly influenced by the [benefit-cost analysis] relying on those benefits, and the MCOS studies used by the utilities to determine the per-kilowatt cost of avoided T&D for use in the BCA. Therefore, the MCOS studies are critical to determining if the DLM programs are being administered in a cost-effective manner, and if changes to such program incentive payment rates are justified.”

The commission said the MCOS studies are being reviewed and may be changed as part of the Value of DER proceeding.

Central Hudson

In addition to rejecting Central Hudson’s request to significantly lower CSRP incentive rates, the commission also rejected its proposal to eliminate its DLC program, which the company said has no participants (15-E-0186).

As it had in 2016, the commission also rebuffed Central Hudson’s request to remove the month of May from the capability period. The company said curtailments are unlikely during May, noting that the maximum demand experienced during the month has not exceeded 88% of the annual peak demand for the last decade. But the commission said “a lack of historic peak load conditions does not preclude future heat waves in May,” and that a change “would detract from tariff uniformity.”

The regulators approved the company’s proposal to increase the trigger for calling CSRP events to 97% of the summer peak forecast load from the current 92%.

The company said that the large number of events called in its service territory using the 92% threshold “led to less than optimal participant performance” in 2016, the commission noted. The 97% trigger would capture the top 10 load hours during the summer and would result in about three events each summer, the company said.

“Although the commission established a consistent 92% CSRP dispatch threshold for all of the utilities in the 2016 DLM order, experience during the 2016 summer capability period suggests that a standard statewide threshold may not result in optimal program performance,” the PSC said. “This is evidenced by the fact that, despite each utility having the same 92% threshold, CSRP planned events were called many more times in utilities with smaller service territories compared to those with a larger footprint. For example, there were 13 CSRP planned events called by RG&E, and nine by Central Hudson, but only four, two and one event called by Niagara Mohawk, NYSEG and O&R, respectively.

“Instead of maintaining a consistent 92% threshold across all utilities, the utilities should design CSRP thresholds that both recognize the unique features of their service territories and seek to balance the interests of CSRP participants and of other customers.”

Niagara Mohawk

While rejecting Niagara Mohawk’s proposal to modify CSRP, DLRP and DLC incentive rates, the PSC approved its proposed expansion of the DLRP to up to eight additional areas of its service territory in 2017 (15-E-0189).

“In only offering the DLRP in certain areas where there are specific T&D infrastructure projects [that] can be avoided, Niagara Mohawk is using the DLRP as a non-wire alternative (NWA) demand response program instead of as a generalized program to support distribution system reliability,” the commission said.

“While Niagara Mohawk will be allowed to continue to operate its DLRP in this manner for the 2017 summer capability period, the commission expects Niagara Mohawk to expand the DLRP to its entire service territory for 2018. Instead of limiting the DLRP only to specific NWA areas, Niagara Mohawk should offer different values in NWA areas for both the CSRP and the DLRP, depending upon whether the need for the NWA is based on load growth, reliability issues or both.”

Orange and Rockland

O&R’s proposed modification to its DLRP incentive payment rates was rejected while its proposed addition of CSRP notices was approved (15-E-0191).

The utility proposed adding a 21-hour advance advisory notice, with intraday two-hour minimum advance notification of confirmation or cancellation of a planned CSRP event. The advisory notice would be triggered when its day-ahead forecasted load is 92% or more of the forecasted summer systemwide peak.

The company said that under the current notification rules, it is unable to cancel a planned event even if conditions change, eliminating the need for load relief.

The commission approved the proposal while also directing Central Hudson, Niagara Mohawk, NYSEG and RG&E to propose similar notifications for 2018. The PSC had permitted an identical modification to Consolidated Edison’s CSRP in December.

Also approved was O&R’s proposal to allow direct participants and aggregators to increase their kilowatt pledge between capability periods and plan for easing the generator emissions and permitting process. As with the notice rule, the commission ordered the other utilities to make similar changes.

Under prodding by the Advanced Energy Management Association, NRG Energy and Direct Energy, the PSC ordered the utilities to standardize their DLM enrollment and settlement processes for 2017 and allow batch enrollments by 2018.

Pre-REV DR

“For me, these demand response programs fit into a specific bucket,” Burman said. “They’ve been in place in New York City for many years, pre-[Reforming the Energy Vision], and should be expanded statewide. They are intended to be cost-effective programs that produce real peak load reductions at critical periods in the summer.”

While last week’s order addresses inter-day reliability problems, Burman said other issues remain unresolved under REV, including utility earnings adjustment mechanisms and setting a “Value D” — the PSC’s plan to calculating the value of distributed energy resources by adding a distribution component (“D”) to wholesale LMP pricing. (See NYPSC Outlines Reforming the Energy Vision Changes.)

“But here, this action is really targeted to those demand response programs,” said Burman. “It does not have a fatal impact on the utility … and all the other proceedings.”

Ravenswood Sale Approved

In a separate electric power case, the PSC approved a petition for the expedited sale of TransCanada’s 2,400-MW Ravenswood generating facility in Queens, N.Y. to Helix Generation for $2.5 billion — with Burman voting to approve a one-commissioner order issued to that effect by Interim Chairman Sayres the previous day.

Burman noted that the order is clear in deferring to NYISO and “FERC on matters that deal with the market power and other pending matters dealing with AC transmission and western New York.”

Noting policymakers’ concerns over market power and state resource planning, Burman said she is looking forward to FERC’s technical conference on May 1-2, “where many of these issues will be fleshed out.” The conference will focus on tensions between state public policies and wholesale markets in NYISO, ISO-NE and PJM (AD17-11).

April 24, 2017

PJM Reliability Conference Raises Questions; Solutions Elusive

By Rory D. Sweeney

PHILADELPHIA — More than 200 stakeholders met at the Philadelphia Airport Marriott on Wednesday and others listened in on the webcast to discuss the meaning of resiliency and reliability on the electricity grid and how to incentivize enhancement of it through PJM’s electricity markets.

PJM Grid 20/20: Focus on Resilience included 16 speakers and featured three panels that slowly built toward a discussion of solutions with the final speakers. However, clear solutions seemed to remain elusive.

“The only way we can properly design the market, the only way we can ensure reliability is through conversations like this: What’s happening, how do we need to change, how do we need to adapt and are we comfortable with where things are going?” said Bill Berg, Exelon Generation’s eastern RTO director. “I said, ‘that was my only firm, concrete solution.’”

Grid 20/20 Panel left to right: Foster, Mroz, Bowring, Berg and Novotny | © *RTO Insider*

Independent Market Monitor Joe Bowring moved the ball forward by suggesting what those conversations should entail.

“We need to define analytically the detailed meaning of resilience,” he said. “What are the metrics?”

Beyond that, speakers largely identified issues and what shouldn’t be done.

“Here’s what we shouldn’t do,” Bowring said. “We shouldn’t pick winning technologies; we shouldn’t provide nonmarket competition for preferred technologies; we shouldn’t make fundamental changes to the market to accommodate preferred answers.”

His answer touched on a consistent battleground during the discussions about whether noneconomic baseload generators should be retained if they provide other benefits. The issue is particularly timely given the zero-emissions credit subsidies approved in Illinois and New York to preserve in-state nuclear plants.

Berg, whose company’s nuclear units are the beneficiary of both of those subsidies, urged stakeholders to consider whether the markets are designed correctly if such out-of-market measures are necessary to preserve the grid’s nuclear fleet. Supporters have argued that ZECs would not be necessary if the markets incorporated the cost of carbon emissions from fossil fuel plants.

“While it’s simple to say, ‘Let’s just rely on markets,’ there’s a reality that we need to recognize as part of the conversation as we transition to a fully competitive market,” he said. “We’re not there yet.”

Bowring argued that the purpose of the markets is to determine whether such plants are indeed desirable.

“The term baseload, think about it: What does that mean?” he said. “A baseload unit was a unit that used to be economic and isn’t anymore, but we still want it to be so let’s make it economic by giving it subsidies.”

Other speakers urged cooperation among all stakeholders to solve the issues.

“This is not an issue that is just left in each of the silos, whether it’s PJM, or it’s a state regulator, or it’s the industry or if it’s one of you companies to try and find solutions,” said Richard Mroz, president of both the New Jersey Board of Public Utilities and the Organization of PJM States Inc. “It is really incumbent upon all of us to do it. … State regulators don’t have the answers. People think we do. We don’t even have a real semblance of that ability as we did to deal with integrated resource plans.”

Joining Bowring, Mroz and Berg on the final panel was Calpine’s Andrew Novotny, who reminded the audience that out-of-market subsidies have impacts that can hurt the market’s overall purpose.

“If we do use state subsidies in order to preserve nuclear plants when they become uneconomic, it’s critical that PJM protects the capacity market and has a price that is protected from what that impact would be,” he said. “There will be a consequence if that’s not done. … We rely on the Capacity Performance product in order to provide revenues that we desperately need to maintain our fuel-oil backup.”

Calpine has oil backup for about 5,000 MW of its natural gas-fired generation to address its CP responsibilities, he said.

Direct Energy’s Marji Philips asked the panelists why proposed solutions continue to cling to previous market structures.

“Everybody’s talking about the past, and putting Band-Aids on the past, instead of looking [at] what’s going to be a very radical future that we can’t imagine today,” she said.

Bowring said the purpose of markets is to define needs and incentivize creative solutions.

“I would say there is no defined market-design problem that requires subsidies as a solution, particularly for specific uneconomic resources,” he said. “One of the things that underlies this whole discussion is an underlying tension between the exogenous requirement to be reliable, NERC-imposed, FERC-imposed and the existence of markets. Markets have successfully met the reliability standards so far, and my point is I think they can continue to do that, but there is that tension. There has always been that tension. The fact that we’re talking about resilience doesn’t make that tension new. It simply makes the challenges more difficult. We need to now think in even more detail about what reliability really means when we include resilience in the definition.”

Mroz warned that state regulators can’t be left to define needs for the market either. For example, he said the BPU is sometimes the last to know about distributed energy resources interconnecting to the grid.

“We don’t have the tools anymore at the state level to identify where all those resources are,” he said. “Something that I have been very vocal about is to ask PJM to ask the industry to be mindful that in the context of meeting these challenges, we’re also mindful at the end of the day of the cost impact that ultimately has to be borne by the consumer.”

April 24, 2017

Offshore Wind Industry Looks for Next Gust of Support

By Jason Fordney

ANNAPOLIS, Md. — A senior federal official told offshore wind energy developers last week that the Trump administration supports their cause as the industry looks to build momentum after putting the first U.S. project into service last year.

“I can attest to the fact that offshore wind is very much a part of the portfolio of energy that [new Department of Interior leaders] have come on board to promote,” Bureau of Ocean Energy Management Acting Director Walter Cruickshank told dozens of attendees April 20 at the 2017 International Offshore Wind Partnering Forum. “So, we can put that question behind us and talk about the future.”

The Obama administration ended its last term with two landmarks in the development of the nascent resource. In December, Deepwater Wind’s 30-MW Block Island Wind Farm off Rhode Island became the first offshore facility to deliver electricity to the U.S. grid, days before developer Statoil Wind US agreed to pay BOEM a record $42.5 million to lease a parcel off New York.

During his campaign, President Trump promised to revitalize the fossil fuel industry and to renege on the carbon emissions cuts promised in the Paris Agreement on climate change, creating concern that his appointees might curtail federal support of renewable energy.

But Cruickshank, a long-time Interior Department official who was deputy director of BOEM at its inception in 2011, noted that the agency completed its seventh competitive lease sale for offshore wind in March. Avangrid Renewables presented the high bid of about $9 million to develop a 122,000-acre wind energy area off Kitty Hawk, N.C., a deal that Interior Secretary Ryan Zinke called a “big win.”

Cruickshank said the agency hopes to identify sites for development off the California shore by June. The seabeds near Massachusetts, New York/New Jersey, the Delmarva Peninsula, the Carolinas, Oregon and Hawaii are also being eyed for development, he said.

At the three-day Annapolis forum, sponsored by the Business Network for Offshore Wind, offshore developers described the unique technical and regulatory requirements for bringing their projects to fruition. Design challenges are highly complex, and the scale of equipment and logistics is huge, while much of the required knowledge and experience is in its infancy in the U.S., relative to Europe.

“This industry does not exist in the U.S. — it is nascent,” said Paul Rich, director of policy development for offshore developer US Wind. The company is vying with Deepwater Wind to be the first to build off the coast of Maryland.

Rich told the forum that it is critical that they collaborate, and told them to be “bold” and to “go big, go large.”

US Wind’s proposed wind farm on an 80,000-acre site 17 miles off Ocean City, Md., would have 187 turbines producing 750 MW. The company won its BOEM lease in August 2014 for $8.7 million and has already invested more than $20 million in its project. The wind farm, which still needs federal permits to move ahead, has a total price tag of $2.5 billion.

The Maryland Public Service Commission is due to decide by May 17 whether US Wind or Deepwater subsidiary Skipjack Offshore Energy will receive offshore renewable energy credits to help fund their proposed projects. The credits, a subsidy that will later be transferred to electricity suppliers to meet renewable energy requirements, spring from 2013 legislation that created a carve-out for offshore wind in Maryland’s renewable portfolio standard. The legislation directs that projects must be 10 to 30 miles off the coast, able to connect to the PJM grid and approved by the state commission.

Skipjack has a much more modest plan for a 120-MW wind farm. The company argues for a more measured approach to development and says its site — 26 miles from the Ocean City Pier and 19.5 miles from its closest point in Maryland — would have much less visual impact.

About 72% of Maryland voters support offshore wind, according to a poll by Annapolis-based marketing analysis firm Opinionworks conducted in 2013. But siting the projects is difficult because of the massive infrastructure and environmental footprints involved. The costs of building offshore are almost three times that of onshore wind according to the U.S. Energy Information Administration’s levelized cost of energy calculations, although offshore turbines are larger and have substantially higher capacity factors.

In addition, even a small visual presence of turbines peeking above the horizon can create complaints in coastal areas. Ocean City officials raised concerns about the visual impact of the proposed US Wind turbines and their possible effect on tourism. The company this month offered to move the project from 12 to 17 miles offshore, adding millions of dollars in costs.

Developers must also deal with the lengthy and costly generator interconnection process faced by land-based generation.

But after setbacks to projects planned off of Atlantic City, N.J., and Martha’s Vineyard, Mass., the industry has reason for optimism. Last August, the Massachusetts legislature approved legislation ordering procurement of 1,600 MW of offshore wind by 2027. (See Massachusetts Bill Boosts Offshore Wind, Canadian Hydro.) In January, New York Gov. Andrew Cuomo proposed the development of 2,400 MW of offshore wind generation off Long Island by 2030. (See Cuomo Proposes 2,400 MW of Offshore Wind by 2030.)

Liz Burdock, executive director of the Business Network for Offshore Wind, says there is a “4.25-GW pipeline” of offshore wind projects in the U.S., large enough to spark a supply chain similar to that in Europe, which has been building utility-scale offshore wind for more than 15 years. The continent boasts 12.6 GW from nearly 4,000 turbines in 10 countries, according to industry group WindEurope.

U.S. developers are looking to utilize the expertise of European offshore wind developers — as well as companies that service U.S. offshore oil and gas drilling — to build capabilities here.

Last week’s forum attracted more than 200 companies and labor unions that would like to be part of that supply chain, in addition to university and government researchers and others.