Page 1406 – RTO Insider

August 15, 2016

MISO Reliability Subcommittee Briefs

MISO wants to know how it can improve frequency response under an evolving generation fleet and is asking for stakeholder involvement to draft an issues statement.

“This isn’t a new topic. The industry has been grappling with the issue for years,” said Durgesh Manjure, MISO’s manager of resource adequacy coordination.

Manjure said MISO hasn’t encountered the frequency response challenges that other systems such as ERCOT have encountered.

“But that doesn’t mean everything is fine and we won’t have to introduce something to keep this reliable trajectory going forward,” Manjure said during an Aug. 10 meeting of the Reliability Subcommittee (RSC). “By no means is this an issue now or next year, but I can’t say that with the same level of confidence for five years out.”

The RTO said that “opportunities exist to improve dynamic models” and performance measurement.

MISO said its changing fleet is driving the frequency response discussion, with coal taking an ever-shrinking share, while gas and wind sources climb. Manjure said MISO relies on coal for “most if not all” of its frequency response, but technological advancements are allowing other generation types to provide a governor-like response to a drop in frequency.

Between 2009 and 2015, MISO’s coal generation capacity dropped from 71.8 GW to 65.2 GW, while wind capacity almost doubled from 7.6 GW to 15 GW. Natural gas, responsible for only 6% of MISO energy production in 2010, now claims 28%; coal’s share fell from 73% to 45% over the same period.

According to NERC’s State of Reliability 2016 report, frequency response reliability in the Eastern Interconnection is expected to decline from the approximate 2,500 MW/0.1 Hz in 2012 to a little more than 2,000 MW/0.1 Hz in 2019.

Manjure said MISO wants to know if its models accurately reflect actual systemwide performance and what fuel mix point would render MISO’s frequency response inadequate. MISO is also asking if it needs to improve its tools that measure frequency response and revise Tariff or market mechanisms relating to frequency response.

“This is very high-level, very open to feedback,” Manjure said.

Manjure asked for stakeholder input that will be used to shape an issues statement in the coming weeks.

Improvement to Pseudo-Ties Process on MISO Horizon

Kyle Abell of MISO’s market planning division said MISO is trying to improve the congestion management process for its increased volume of pseudo-ties.

MISO said it has experienced escalating pseudo-tied generation with load farther from the seams in 2016. In the 2015/16 planning year, MISO-based generation pseudo-tied into PJM equaled only 155 MW; in the 2016/17 planning year, the amount is expected to reach about 2,000 MW. In the 2017/18 planning year, pseudo-ties are expected to creep toward 2,800 MW, with many of the deeper pseudo-ties sent to attaining balancing authorities with “very limited or no modeling-based visibility” of how their usage affects the larger MISO system.

Abell said MISO is contemplating new requirements for approving a pseudo-tie, including notification, pre-assessment and conditional approval steps. In addition, the RTO may set out requirements for an attaining balancing authority’s network model for proposed pseudo-ties. Currently, MISO reviews and approves pseudo-tie requests, while balancing authorities are responsible for market-to-market redispatch.

MISO asked stakeholders for suggestions to improve its pseudo-tie congestion management before Aug. 26. The RTO also said it would meet with neighboring balancing authorities and RTOs and its Independent Market Monitor to discuss the issue. Abell said he would make another pseudo-tie presentation at the Aug. 16 Planning Subcommittee meeting.

MISO plans to revise its processes around congestion caused by pseudo-ties through November, in time to draft a work plan to implement the changes in December.

Smooth Operations in MISO Despite ‘All-Time Hottest’ July

MISO operations performed well in July despite several hot weather and severe weather alerts, said Steve Swan, MISO senior manager of dispatch and balance.

Swan said July 2016 was the “all-time hottest July” for multiple cities in the southern portion of the MISO footprint. It was also the driest month since MISO’s creation for some southern MISO locations. Load peaked at 120.6 GW on July 21.

MISO reported that July 10, 12 and 20 fell outside of its unit commitment performance targets since forecasted load didn’t materialize due to thunderstorm activity; units that were preemptively called up had to stay online to fulfill their minimum run times. MISO also had one maximum generation event in July.

July also marked the first month MISO was required to abide by NERC’s balancing authority area control error limit (BAL-001-2) standards, which limit interconnection frequency errors to less than 30 minutes. Swan said MISO did not experience an error lasting longer than 15 minutes event in July.

RSC Chair Tony Jankowski commended MISO for its operations in the face of the hot weather. “We’ve had a pretty good summer so far, and MISO’s gotten us through some hot weather we haven’t seen in a while,” Jankowski said.

Winter is Coming and Coordinated Seasonal Assessment is Scoped

With Labor Day looming, MISO is already thinking about winter. Its 2016/17 winter Coordinated Seasonal Assessment, which assesses risks and system capabilities will include four main analyses, said MISO’s Katie Hulet:

A steady-state AC analysis to study the effect of simple and complex contingencies;
An analysis identifying large phase angle differences associated with reclosing a transmission line;
A voltage stability analysis that will assess four critical interfaces for high transfers in combination with transmission and generator outages, which can cause stability issues; and
A first contingent incremental transfer capability analysis to study the impact of high megawatt transfers and flowgate limitations. This analysis will examine six transfers in addition to wind transfer sensitivity.

MISO also will use only approved retirements and planned and forced transmission and generation outages lasting two months or more between December and February in its assessment.

Hulet said MISO would return to the RSC in November to provide the study’s results.

— Amanda Durish Cook

August 15, 2016

MISO to Begin Charging Tx Fees on PJM Exports

By Amanda Durish Cook

MISO last week filed revised Tariff language allowing it to recover costs for multi-value transmission projects that benefit PJM customers by charging a fee on exports to PJM (ER10-1791-003). The Aug. 12 compliance filing requested the new language be retroactive to July 13, 2016.

Last month, FERC partially lifted the three-year-old restriction on MVP allocations for exports in response to a 2013 remand from the 7th U.S. Circuit Court of Appeals. (See FERC Looks Again at Export Pricing for MISO MVPs.)

MISO Transmission Fees PJM — Foundations are laid for Ameren’s Illinois Rivers transmission project, a 345 kV line stretching from West Adair, Mo., to Sugar Creek, Ind. The line consists of five multi-value projects, and portions are expected to come online as early as this year.

The commission said it was persuaded by the large-scale wind buildout “capable of serving both MISO’s and its neighbors’ energy policy requirements.”

It also cited “the reported need of PJM entities to access those resources; and the reported need for MISO to build new transmission facilities to deliver the output of those resources within MISO for export.”

“Given these changes, it is appropriate to allow MISO to assess the MVP usage charge for transmission service used to export to PJM just as MISO assesses the MVP usage charge for transmission service used to export energy to other regions,” FERC concluded.

MISO created the MVP category six years ago for projects that address more than one reliability or economic need across multiple transmission zones. The RTO originally intended to allocate project costs to all of its load and exports, but FERC excluded the export charge because of concerns over rate pancaking.

Chris Miller, FERC’s liaison to MISO, said the RTO removed Tariff language that had prohibited it from charging exports. Affected portions include Attachment MM, Schedule 26-A, Schedule 39 and Attachment L.

MISO also made an informational filing in early August detailing multi-value, market efficiency and baseline reliability projects approved during the Transmission Expansion Plans in 2014 and 2015 (ER13-186, ER13-187). While 140 baseline reliability projects were approved in the two years, only one market efficiency project was greenlit.

The RTO did not approve any MVPs in 2014 or 2015. It said its $6 billion 2011 MVP portfolio — 17 projects in various transmissions zones over nine states — left only local reliability projects to be addressed for the time being.

Three of the projects are in service, with the remainder scheduled to be operational in three to five years.

August 15, 2016

PJM Operating Committee Briefs

VALLEY FORGE, Pa. — PJM is considering providing generation operators an indicator to signal that the RTO has entered emergency conditions, which triggers a performance assessment hour under Capacity Performance rules.

The RTO will determine if there should be any delay in the notification process and, if so, for how long, PJM’s Rebecca Stadelmeyer said. Stakeholders requested that PJM also ensure the signals don’t create any type of market advantage.

Stadelmeyer also clarified that non-ramp-limited basepoints have no impact on calculating either performance bonuses or nonperformance charges during a PAH.

The question arose because generators had been asking for the basepoints to be sent via PJM’s network, thinking they could help estimate units’ expected performance, Stadelmeyer said.

Non-ramp-limited basepoints are theoretical expectations based entirely on the economics of the current LMP and regardless of the unit’s actual capabilities. Ramp-limited basepoints, however, are developed from information about each unit submitted by operators into PJM’s systems.

Nonperformance charges are imposed when a unit’s output fails to meet its expected performance, and bonuses occur when actual output exceeds expected performance without exceeding PJM’s dispatch instructions. Expected performance is calculated by multiplying a balancing factor by the amount of a unit’s unforced capacity (UCAP) that clears as CP in a Base Residual Auction.

Balancing factors are hard to estimate, Stadelmeyer said, so she urged using the maximum 1.0 to identify the highest possible expectations.

PJM also clarified that the difference between UCAP and installed capacity (ICAP) is also available for bonuses as long as the RTO has dispatched the unit to that level.

In May, FERC rejected Tariff changes that would have exempted a capacity resource from nonperformance charges if it was following the RTO’s dispatch instructions and operating at an acceptable ramp rate during periods of high load. The changes were designed as an interim solution to guard against generators self-scheduling prior to a performance assessment hour in order to avoid nonperformance charges. (See FERC Rejects Ramp Rate Exception in PJM Capacity Rules.)

Post-Polar Vortex Tools Enable PJM to Better Face Severe Weather

Thanks in part to new forecasting, scheduling and reserve-checking tools implemented after the polar vortex of 2014, PJM was better able to weather a seven-day July heatwave, PJM’s Chris Pilong told the Operating Committee last week.

The RTO recorded its 13th-highest peak load at 151,822 MW on July 25, a day that saw an average LMP of $35.51. During the hot spell, which ran July 21-27, the daily average LMP ranged from $25.88 on July 26, which recorded a peak load of 143,654 MW, to $42.72 on July 27, which saw a peak load of 146,166 MW.

Pilong said the experience was good news for PJM, which wanted to gauge the self-scheduling behavior of generators now that Capacity Performance is in effect. The RTO doesn’t want generators to disregard its dispatch orders and self-schedule more capacity to avoid penalties when they believe they are approaching a performance assessment hour. (See “Ramp Rate Approach Would Excuse Nonperformance Penalties,” PJM Markets & Reliability and Members Committees Briefs.)

“The day-ahead self-scheduled megawatts didn’t change much from the past few summers,” he said. “We’re not seeing a big shift.”

Day-ahead self-schedules for July 25 stood at 69,476 MW, compared with 68,649 MW a year ago, when load hit 143,633 MW. In real time, generators self-scheduled 73,177 MW, compared with 76,430 MW a year ago.

Self-scheduled units are price takers and cannot set marginal prices; they also are ineligible for operating reserve credits.

July 25 was the first time under the new market construct that PJM issued a maintenance outage recall. It canceled 11 planned outages, totaling 124 MW over 72 hours. Eight of them, a sum of 48 MW, were online by noon July 25; the remaining three, totaling 76 MW, did not return and were converted to forced outages.

An RTO-wide hot-weather alert was issued July 22-25. A heat advisory was issued July 21 in the ComEd zone and July 26-28 in Mid Atlantic and Dominion.

The grid experienced no transfer or interconnection reliability operating limits (IROL) issues during the hot weather, Pilong said.

However, two 765/345-kV transformers tripped in different parts of the system, causing local congestion. (See “Grid Remains Strong During Recent Heat Wave,” PJM Markets and Reliability and Members Committees Briefs.)

PJM’s new tools address two scheduling concerns leading into the polar vortex. Operators’ ability to view the capacity position for the next several days was limited, as was their capacity to capture generator reserves in real time in order to validate their calculations.

In June 2014, PJM rolled out its “long lead” tool, which consolidates load forecasts, safety margins and generator data, and adopted a new procedure for scheduling generation that includes a seven-day look-ahead.

Last September the RTO developed an instantaneous reserve check, allowing it to validate unit reserves in real time.

Pilong said the new tools helped reduce balancing operating reserve (BOR) payments. BOR payments totaled $18.1 million from June through August 2015. That amount stood at $10.1 million through July 26, 2016.

Uplift payments for July 25 came to nearly $1.1 million, compared with $447,118 for the hottest day in 2015, which occurred on July 28.

Metering Task Force Presents Proposal to Improve Clarity

PJM presented the first read of an 11-point proposal for manual and Tariff changes to close the gap between PJM’s metering requirements and members’ understanding of the rules.

The proposal was outlined by Nancy Huang of the Metering Task Force, which was formed by a problem statement approved Sept. 8. (See “Metering Requirements to Receive Overhaul,” PJM Operating Committee Briefs.)

The group also recommended two topics for further study: minimum metering requirements for location and density to ensure system observability, and metering requirements for distributed generation.

The revisions aim to reduce the risk of non-compliance, provide clarity around the specifications and design of new equipment, improve the energy management system’s state estimation solution and maintain operation reliability and market fairness.

The proposal is set to go before the Members Committee on Sept. 29, with a FERC filing expected in October.

Systems Information Committee Heads into the Sunset

Members approved sunsetting the Systems Information Committee.

Topics related to the energy management system will be assigned to the Data Management Subcommittee (DMS), which will meet next on Aug. 25. Remaining topics will be transitioned to the new Tech Change Forum, which will hold its first meetings Sept. 27-28.

To accommodate the changes, the Operating Committee also approved modifying the DMS charter.

The DMS will now function as a joint subcommittee, with generator and transmission owners addressing pertinent issues and TOs considering topics applying only to them.

— Suzanne Herel

August 15, 2016

Company Briefs

Energy Future Holdings last week filed a third amended joint reorganization plan and related disclosure statement with the U.S. Bankruptcy Court in Delaware.

EFH is set to begin its latest attempt to exit bankruptcy this month after the deal at the center of a prior plan fell apart after it had been confirmed by Bankruptcy Court Judge Christopher S. Sontchi.

Energy Future, the largest power company in Texas, filed for Chapter 11 in April 2014 after it failed to meet its debt obligations as electricity prices weakened. The bankruptcy is one of the largest ever in the United States.

More: Bankrupt Company News

Troubled Kemper Needs Another Month, $43 Million

The controversial, multi-billion-dollar Kemper Power Plant, which began making synthetic gas from coal July 14, will take an additional month to finish and cost an extra $43 million, Mississippi Power Co. announced last week.

The oft-delayed coal gasification plant, whose costs have increased to $6.8 billion, is now planned for a Halloween completion. The most recent cost overruns prompted Mississippi Power Co. to write off $81 million in losses in its second quarter.

Mississippi Power parent Southern Company said it needs the additional month to achieve “sustainable operations” by adjusting the two gasifiers that transform soft lignite coal into synthetic gas and to complete testing on the technology that removes carbon dioxide from the gas.

More: Jackson Free Press

Black Hills Energy Starts $54 Million Tx Project

Black Hills Energy started construction on a $54 million, 147-mile transmission line running from eastern Wyoming to western South Dakota. Planning for the project took 10 years, and construction crews started cleaning land on the route last week.

Most of the land is owned by the state or federal governments, but agreements were reached with 24 property owners to allow access to their land. A company spokesman said it would be completed by mid-2017.

More: Rapid City Journal

Chesapeake Gives Up Barnett Assets to Private Group

Chesapeake Energy Corp. said it has agreed to hand over its Barnett Shale holdings to a private-equity-backed operator. The move allows Chesapeake to avoid almost $2 billion in pipeline contracts.

Chesapeake issued a statement saying it will give its interests in the North Texas Barnett region, estimated to be worth as much as $1 billion, to First Reserve Corp.-backed Saddle Operating LLC. The move will cut Chesapeake’s shipping and processing costs by $715 million between now and the end of 2017 and will eliminate $1.9 billion in long-term pipeline agreements.

The Barnett Shale, once at the forefront of the U.S. shale boom, lost its competitive advantage when gas prices collapsed and it was eclipsed by lower-cost production areas closer to Eastern markets. The Barnett is Chesapeake’s second-smallest production region, accounting for 10% of the company’s output.

More: Bloomberg

Duke Issuing $3.75 Billion in Debt to Finance Piedmont

Duke Energy will issue three series of unsecured bonds, totaling $3.75 billion, to help finance its $4.9 billion purchase of Piedmont Natural Gas. The first series, with an interest rate of 1.8%, will be due in 2021; the second series, at 2.65%, will be due in 10 years. A third series, carrying the highest interest rate of 3.75%, will be due in 30 years.

The company said it expects the purchase to close by the end of this year, but it could come as soon as the North Carolina Utilities Commission approves the merger. Hearings on the purchase concluded last month, and briefs are due at the end of this month.

More: Charlotte Business Journal

SolarCity Panel Plant Start Date Moved Up

SolarCity plans to make solar panels in its Buffalo factory by the end of next June, several months earlier than its previous estimate.

Improvements in the equipment the factory will use, and a more efficient plant layout, should allow the factory to make more solar panels than would have been possible under its original design. The plant’s capacity was pegged initially at 1 GW, and company officials would not say how much extra capacity it will add.

SolarCity initially had planned to start making solar panels this year, but slower growth and financial constraints delayed some investment, pushing the production timetable until late 2017.

More: The Buffalo News

Exelon Outlines Growth Strategy, Continues to Push Reforms

At Exelon’s Analyst Day last week in Philadelphia, the company outlined a growth strategy that includes investing in its six electric and gas utilities and adopting innovative technology.

Exelon plans to invest $25 billion in infrastructure and smart grid technology over the next five years.

The company also said it will continue to push policy and market reforms to preserve nuclear plants that face economic challenges.

More: Business Wire

Fire at Four Corners Plant in NM During Decommissioning Work

A chemical fire broke out during the decommissioning of three units at the Four Corners Power Plant in northwestern New Mexico Aug. 11, forcing the plant’s evacuation. The fire was reported at 10:54 a.m. and was extinguished shortly after 1 p.m.

A spokesman for Arizona Public Service Co., which operates the plant, said the fire erupted as crews were working to dismantle a crystalline brine concentrating tower used to purify water for cooling equipment.

APS does not expect the incident to impair its plans to close the units by the end of the year. The remaining two units were offline for maintenance and not affected by the fire.

More: Farmington Daily Times

DTE Plant in St. Clair Burns for 12 Hours

A fire at DTE Energy’s St. Clair County coal-fired power plant burned for 12 hours Thursday night into Friday morning before firefighters were able to extinguish the blaze. There were no injuries at the plant, which is located on the St. Clair River in East China Township.

The fire was reported about 6:30 p.m. Thursday, and all employees were evacuated after shutting down all remaining units. Company and state officials continued to work to determine the cause of the blaze.

The plant is among three slated for retirement by 2023.

More: The Detroit News

August 15, 2016

CAISO Plans to Protect Small Utilities from High Network Upgrade Costs

By Robert Mullin

A new CAISO proposal seeks to shield smaller participating transmission owners from outsized network upgrade costs for interconnecting generation built to serve load outside that TO’s service area.

“The issue is — to what extent should a local area incur costs for resources that are clearly not serving that area?” Neil Millar, CAISO executive director of infrastructure development, said during an August 8 call to discuss the proposal.

“Network upgrades on low-voltage facilities for [TOs] with a relatively low rate base can significantly increase costs [for those PTOs],” said Steve Rutty, the ISO’s director of grid assets. “Similar upgrades would not have much of an impact” on larger TOs.

The proposal stems from the situation confronting Valley Electric Association, which serves 45,000 customers located in a 6,800-square-mile region straddling the California-Nevada border. The utility — CAISO’s only out-of-state member — has about 100 MW of load. Two projects awaiting interconnection will bring 100 MW of new generation into Valley’s territory, with more entering the queue, according to Rutty.

Valley Electric Association Territory (CAISO) - utilities high network upgrade costs — Valley Electric Association, which joined the ISO in 2013, serves about 45,000 customers in its 6,800 square mile territory.

“So we’re looking at hundreds of megawatts for an area with just 100 MW of load,” Rutty said.

CAISO’s Tariff requires a TO to reimburse its generator interconnection customers for the costs of local reliability and deliverability network upgrades necessary to connect to the transmission network. With regulators’ approval, the TO can then include those reimbursement costs in its rate base and pass them on to ratepayers through either a high- or low-voltage transmission access charge (TAC). The ISO considers any line under 200 kV to fall into the latter category.

Postage Stamp Rate

Unlike CAISO’s high-voltage TAC, which is allocated to all ISO ratepayers at a “postage stamp” rate based on the aggregated revenue requirements of all TOs owning high-voltage lines, the low-voltage TAC is charged only to customers within the service area of the TO owning the facilities.

That arrangement could impose an unfair financial burden on ratepayers served by small TOs such as Valley.

“[I]f a large generator or a large number of generators with significant low-voltage network upgrade costs interconnect to a [TO] with a relatively small rate base, that [TO’s] rate base may increase significantly and can result in rate shock to its ratepayers,” the ISO said in its straw proposal.

The ISO estimates that $25 million in network upgrade costs would boost Valley’s low-voltage TAC from $6.26/MWh to $12.13/MWh — a 94% increase.

“There’s a considerable amount of interest in Valley for renewables,” said ISO attorney Bill Weaver. “If all the projects come online, $25 million is not unreasonable to expect.”

But those projects will not provide a “commensurate benefit” for the utility’s ratepayers, CAISO said.

The ISO has proposed two options to address the issue, which it expects to occur again if the ISO expands into other areas of the West and takes on additional small TOs.

The first option would allow a TO to roll “generator-triggered” low-voltage network upgrade costs into its high-voltage revenue requirement for recovery through its high-voltage TAC. The rationale: Any new generation will provide energy for the entire ISO market or support policy goals such as resource adequacy, reliability and increased renewables.

Under this scenario, $25 million in upgrades in the Valley area would translate into a 1.5-cent/MWh — 0.14% — increase in high-voltage TAC rates shared by all ISO ratepayers.

“This option would apply to all PTOs, is straightforward and would be fairly simple to implement,” the ISO said.

“This raised the question of whether local upgrades are helping the local area — which brought up the issue of some kind of cost sharing,” Millar said. “Which brought us to option two.”

The second, more complicated, option would split cost recovery for low-voltage upgrades between a TO’s low-voltage and high-voltage TACs. The split would be assessed in such a way as to cap increases to a TO’s low-voltage revenue requirement and TAC. Any amount above the cap would be applied to the TO’s high-voltage revenue requirement and thereby rolled into the ISO’s TAC.

Three Options

The ISO is considering three methods for calculating the split:

Place a cap on the cost share of interconnection-driven upgrades assigned to a TO based on a percentage — possibly 5% — of the TO’s low-voltage base rate. TO’s with smaller base rates would be capped at significantly lower amounts than the larger investor-owned utilities.
Limit incremental increases to a TO’s low-voltage revenue requirement based on a percentage of the TO’s annual low-voltage revenue requirement.
Limit incremental increases in the revenue requirement to a percentage of the high-voltage TAC revenue recovered from the TO’s ratepayer base.

“This last method would make sense because it limits exposure of a local area group of customers to a percentage of their high-voltage TAC payments,” the ISO said. “As such, a utility twice the size of another could reasonably absorb twice the local impact of interconnection-related low-voltage network upgrades compared to a utility with a much smaller customer base.”

“We want to know the justification for the proposal,” said Lanette Kozlowski, director of regulatory relations at Pacific Gas and Electric. “Is it just the rate impact for the customers of [Valley Electric]?”

“That’s overly simplistic,” said Millar. “The cost issue certainly puts a spotlight on it, but it’s more about resources being developed in an area that won’t be serving that area.”

“How is this going to align with the other utilities where you’re connecting to the network and it’s being fully paid for by the project?” asked Don Davie, vice president with Wellhead Electric. “What are you thinking about for cost-causation for the actual project?”

“We’re not really going to propose shifting the costs to interconnection customers,” Millar said.

ISO staff plans to submit a final plan to the Board of Governors in December. Stakeholders must submit comments about the straw proposal by Aug. 19.

August 12, 2016

UPDATED: PJM, NYISO Seek Input on Replacing Con Ed-PSEG ‘Wheel’

By Peter Key and Rory D. Sweeney

VALLEY FORGE, Pa. — PJM and NYISO held a joint meeting on Monday to get stakeholder feedback on their effort to replace a decades-old power-flow protocol.

The RTOs must have a new protocol in place next May when Consolidated Edison terminates a “wheel” arrangement that allows it to move 1,000 MW from generators in upstate New York through Public Service Electric and Gas facilities in northern New Jersey to serve its load in New York City.

The main question is how to handle eight phase angle regulators (PARs) that currently govern the direction of flows on lines connecting the PJM and NYISO grids. There are one each on the A, B and C lines that flow the 1,000 MW from PSE&G into New York; three south of Waldwick on the J and K lines that flow the energy into PSE&G from upstate New York; and two on the Branchburg-Ramapo 5018 line.

At PJM, the situation is being overseen through the Planning, Market Implementation and Operating committees. During last week’s Planning Committee meeting, PJM’s Mark Sims explained that the PARs have more physical limitations than HVDC ties, which can be more specific in regulating flow. The PARs can be set to certain “tap positions” to “bias” the flow, but each of them has a limit of 20 adjustments per day and 400 per month.

At Monday’s meeting, PJM and NYISO staffers gave presentations on the operational aspects and market impacts of the wheel replacement.

Phil D’Antonio, PJM’s manager for reliability engineering, said the new protocol must protect reliability, manage congestion, preserve competitive market behavior and minimize the impacts to PJM and NYISO loads. It also must be able to be facilitated with the existing PAR technology and implemented in both grid operators’ market models.

On the markets side, PJM and NYISO are proposing adding the J, K, A, B and C lines into the single PJM-NY AC Interface and implementing market-to-market coordination using the PARs on the lines’ interfaces. The RTOs said the proposal uses existing market constructs in both their markets, increasing the likelihood it can be implemented by next May.

The review of the new protocol will include an N-1-1 analysis.

PJM and NYISO have agreed not to change their treatment of Rockland Electric Co.’s load, 80% of which is supplied by the 5018 line, with the remainder flowing over several western ties across the New York-Pennsylvania border.

One of the proposals being evaluated — the “natural flow” — would send about 500 MW from NYISO into PJM via the J and K lines and then into New York City via the A, B and C lines, Sims said. Stakeholders have questioned allowing this because it appears to provide similar service to the “wheel” without the same transmission payments. Completely curtailing that natural flow, or modeling 0 MW, threatens to “max out” the PARs’ thermal and voltage limits, Sims said.

Among the “high-level” considerations that the grid operators are discussing are biasing the flows applied to the J, K, A, B and C lines by accounting for the natural flow, and then applying agreed-upon interchange percentages to each interface (5018 and ABC) to reduce congestion.

NYISO published a white paper on the process and will partner with PJM to publish another one that includes PJM’s perspective, which will be released in conjunction with a meeting of NYISO stakeholders.

Stakeholders have asked PJM to create a contingency plan for extended outages of the PARs.

August 12, 2016

NRG Continues to Pare Down Businesses, Affirms Guidance

By Tom Kleckner

NRG Energy continues to retrench after a dismal 2015, announcing last week it will sell its stake in the California Valley Solar Ranch and restructure its GenOn unit, whose acquisition in 2012 nearly doubled NRG’s generation portfolio.

New Jersey-based NRG also said it had sold two Illinois gas plants for $425 million, helping the corporation deliver $779 million in adjusted earnings before interest, taxes, depreciation and amortization (EBITDA) for the quarter. NRG has generated almost $1.6 billion in adjusted EBITDA — or cash flow — this year, putting it in the upper range as it reaffirmed its guidance for 2016 ($3 billion to $3.2 billion).

“We have a lot of the summer ahead of us. I think it’s just prudent to keep our guidance the way we had it,” interim CEO Mauricio Gutierrez said during a conference call with analysts. “We’re very comfortable with the positon we have. We still have August and September, which can be really hot in Texas.”

nrg energy — NRG Energy’s El Segundo Plant *Source: NRG*

NRG said it has reached agreement to sell its 51% stake in the 250-MW California Valley solar project for $78.5 million in cash plus assumed debt to NRG Yield. NRG Yield is a separate, publicly traded company that has 4,438 MW of renewable and conventional generation under contract; NRG Energy owns 55.1% of the yieldco’s outstanding common stock.

The company also said GenOn has appointed two independent directors and retained restructuring advisors “to help navigate the [restructuring] process efficiently and judiciously” in a bid to reduce its “excessive” leverage ratio.

GenOn, which has $2.6 billion in debt, is expected to generate only $335 million in EBITDA in 2016 — a leverage ratio of 7.7, far above the 4.2 ratio for the company as a whole and the 4.0 ratio the company is seeking to reach by the end of the year.

NRG’s $1.7 billion acquisition of GenOn boosted the company to 47 GW of generating capacity, making it the largest competitive generator in the U.S. But the 22.7 GW acquired from GenOn — coal, natural gas and oil — have not fared well due to the entry of increasingly competitive renewables and more efficient plants burning cheap shale gas.

NRG said its second quarter net loss of $276 million ($0.61/share) — worse than its $9 million loss a year ago — resulted from $198 million in impairments and losses on asset sales and an $80 million loss related to extinguishing debt.

Excluding one-time charges, the company’s loss was $0.04/share, below Zacks Investment Research’s consensus expectations of a $0.03/share profit. NRG reported $2.64 billion in quarterly revenues, well below Zacks’ consensus projection of $3.45 billion.

The company had a net loss of $229 million ($0.37/share) for the first six months of this year, after recording a $6.44 billion loss in the fourth quarter of 2015, which ended with the resignation of CEO David Crane.

NRG shares were down 5.6% in the two days following the Aug. 9 earnings announcement, closing off 75 cents at $12.76 Wednesday.

NRG serves more than 3 million residential customers throughout the country, primarily in Texas and the Northeast.

August 10, 2016

ISO-NE Ordered to Justify Cost of Winter Reliability Program

By William Opalka

Following a directive from a federal appeals court, FERC ordered ISO-NE to provide more information proving that the 2013-14 winter reliability program resulted in just and reasonable rates (ER13-2266).

“ISO-NE should request from program participants information that will enable ISO-NE’s [Internal Market Monitor] to evaluate the competitiveness of the program and whether any amounts exceeding a participant’s cost of providing the winter reliability service are indicative of market participants exercising market power in that program,” FERC wrote in the Aug. 8 order.

ISO-NE previously said such information was commercially sensitive and should not be disclosed.

Under the program, selected resources were compensated through a monthly payment derived from the resources’ bids under an “as-bid” pricing mechanism, rather than a uniform clearing price, FERC wrote.

The program paid for demand response resources and some of the carrying costs for dual-fuel generators that stored oil on-site.

FERC granted ISO-NE expedited approval for the program in late 2013 due to concerns that the region might fall short of generation due to the retirement of coal-fired units and tight natural gas supplies.

Although ISO-NE estimated the program would cost no more than $43 million for up to 2.4 million MWh of energy, the RTO filed for approval of bids totaling nearly 2 million MWh at a cost of $78.8 million, which FERC accepted.

TransCanada Power Marketing argued that this cost disparity required more scrutiny and that the commission did not have adequate information to determine whether the bid results were just and reasonable.

After FERC denied a request for rehearing in 2014, the company appealed to the D.C. Circuit Court of Appeals. On Dec. 22, 2015, “the court agreed with TransCanada’s argument that the record was devoid of any evidence regarding how much of the program’s cost was attributable to profit and risk mark-up,” according to the commission order.

The order directs ISO-NE to request from market participants the basis for their bids, including the process used to formulate the bids. The commission also required an analysis from the IMM and a recommendation from ISO-NE on the reasonableness of the bids within 120 days.

FERC also said ISO-NE “may choose to request” information justifying suppliers’ bids in in the subsequent years’ reliability programs.

August 10, 2016

MISO Will Use ATC Plan to End Upper Peninsula SSR

By Amanda Durish Cook

MISO will ask FERC to end a system support resource agreement in Michigan’s Upper Peninsula, saying its reliability concerns will be addressed by American Transmission Co.’s transmission reconfiguration until an upgrade expected in service by the end of 2020.

MISO said ATC’s proposal to open transmission circuits and split the western UP load pocket into two radially-fed areas “avoids [the] risk of cascading loss of load during prior outages,” allowing the termination of White Pine Unit 1’s System Support Resource (SSR) agreement.

MISO plans to file to terminate the SSR agreement following a 90-day notice, Joe Reddoch of MISO’s System Support Resource Planning Group said during a meeting of the West Technical Study Task Force Aug. 8.

Reddoch said that the two-radial configuration would be used only during planned outages or when one of the area’s two 138kV lines is unexpectedly out of service. The load pocket would be served by the remaining 138-kV line and the Conover 69-kV line.

ATC submitted the proposal to MISO in late July. (See ATC Plan Could Eliminate White Pine SSR; Refunds Coming on Presque Isle?)

“Some of these are day-long outages. I think the longest one we looked at is somewhere in the order of a week,” Reddoch said.

MISO concluded the two-radial configuration would result in only a small increase in the risk of loss of load.

The load pocket in the western Upper Peninsula around White Pine — about 68 MW during shoulder periods and 80 MW in the summer — is supported by two 138-kV circuits and one 69-kV line. An outage of one 138-kV line followed by the loss of the second line “results in severe overloads and voltage collapse in the local load pocket,” MISO said.

The RTO said ATC’s plan would result in a “limited” increase in the risk of a consequential load shed, which could be managed within the RTO’s planning and operating criteria, which allows mitigation through reconfiguration.

“From our perspective, this is an acceptable alternative,” Reddoch said. “The radial reconfiguration isn’t unheard of in the system. It may not be ideal, but it’s certainly acceptable.”

Richard Bonnifield, an attorney for White Pine Electric Power, said stakeholders were being “blindsided” by the introduction and acceptance of ATC’s plan in the same stakeholder meeting and asked for a reliability impact analysis on the removal of White Pine. Reddoch said a reliability analysis would not provide any additional information and would serve only to “unnecessarily” delay implementing the solution.

Bonnifield fired back that the stakeholder process regarding the SSR removal was “unstructured.” Other stakeholders asked for more time to assess the alternative.

“Our assessment does not require any extensive analysis. This reconfiguration is already in place for unplanned outages. This has already been an accepted process for unplanned conditions. I don’t think we can conclude that it’s not acceptable,” Reddoch said. Ken Copp, a strategic technical advisor with ATC, confirmed that ATC’s system in the western Upper Peninsula would return to a configuration prior to the 1990s when Wisconsin Electric Power Co. and ATC tied their lines together.

Some stakeholders asked Copp why the lines were tied together in the first place.

“Back in that day, contract paths were a big deal, especially for wholesale customers. It achieved some contract path goals, but we have to label that as anecdotal, not something that’s documented,” Copp said.

Some stakeholders said the transmission reconfiguration would not be as reliable as keeping the SSR in place.

Reddoch responded that the plan isn’t in violation of planning criteria and presents a no-cost alternative for ratepayers. “It might not be ideal, but even an SSR isn’t ideal,” he said.

White Pine Electric Power requested retirement of White Pine Unit 1 in April 2014. The current SSR agreement was expected to last until 2017.

The long-term solution for the reliability concerns that gave rise to the SSR is a $100 million plan to convert the 75-mile, 69-kV transmission path from Lakota Road to Mass to Winona to 138 kV. The project, included in MISO’s 2015 Transmission Expansion Plan, is slated to be finished in December 2020.

Angela Castle of the Michigan Agency for Energy said ATC’s solution would be “much less onerous” on ratepayers.

Steve Leovy, a transmission engineer at WPPI Energy, told stakeholders that ATC presented the alternative solution despite not being directly affected by SSR costs.

“ATC isn’t in this; they don’t have to pay the SSR costs. Our ratepayers have to pay the SSR costs. We are supportive of this … and we don’t take the increased risk of load loss lightly,” Leovy said.

Reddoch said MISO will work with ATC in the coming weeks to revise the company’s operating guide to remove White Pine availability and introduce the reconfiguration plan. Details of the revised operating guide will be kept confidential per MISO procedure.

August 9, 2016

UPDATE: ERCOT Surpasses 70,000 MW, Sets Six Hourly Peak Demand Records

By Tom Kleckner

ERCOT has broken the 70,000-MW barrier for the first time, setting six new systemwide hourly peak demand records this week.

The Texas grid operator registered its latest record peaks Thursday when system load reached 71,197 MW between 4 and 5 p.m., after having climbed to 71,043 MW between 3 and 4 p.m.

That smashed records set Wednesday (70,572 MW) and Monday (70,169 MW), which had bettered the previous mark of 69,877 MW set last August. The grid fell short of another record Friday, peaking in the 4 p.m. hour at 70,343 MW.

Real-time settlement prices spiked to $220.37/MWh systemwide at 2:15 p.m. Thursday. The Rayburn load zone was still settling at $228.72 at 4 p.m., with the Whitetail Wind Project in the congested North zone offered into the market at as much as $1,000.14 during the 4 p.m. hour.

ERCOT’s peak demand first surpassed 70,000 MW between 3 and 4 p.m. Monday, before setting a short-lived record between 4 and 5 p.m.

With triple-digit temperatures settling over the state, the Texas grid operator expected load to peak above 70,000 MW again Thursday between 4 and 6 p.m. Whether it sets a new record remains to be seen.

“Welcome to August,” ERCOT CEO Bill Magness told the Board of Directors Tuesday morning. “Usually, peak records set in August don’t normally last.”

Magness was quick to note ERCOT did not have to call an emergency alert Monday, saying, “It was a great performance by the system and the people who make it work.”

“These hot summer days always put our grid to the test,” said ERCOT’s director of system operations, Dan Woodfin, on Wednesday. “We have had sufficient generation available to carry us through these high-demand periods.”

ERCOT staff said it expects operating reserves to drop below 3,000 MW this week. Its final summer Seasonal Assessment of Resource Adequacy said the ISO had 78,434 MW of generation capacity available and projected a peak summer demand of 70,588 MW.

The Texas grid operator also set a new weekend peak demand record Sunday when it hit 67,000 MW.

Staff said it expects consumption to drop next week and believes it has sufficient generation as long as resources are available. ERCOT’s final summer Seasonal Assessment of Resource Adequacy said the ISO had 78,434 MW of generation capacity available and projected a peak summer demand of 70,588 MW.