Page 1428 – RTO Insider

June 13, 2016

PJM Operating Committee Briefs

Beginning this year, Capacity Performance units no longer would be compensated for participating in cold weather testing, which is set to be continued under a plan that the PJM Operating Committee will be asked to endorse in August.

The program is voluntary, noted PJM’s David Schweizer, and generators may self-schedule their own testing.

PJM Operating Committee Briefs — As PJM moves to a Capacity Performance model, designed to avoid the outages experienced during the Polar Vortex, the RTO wants to continue winter testing but end generator compensation.

The rationale behind the change, which was first mentioned in April, is that PJM expects generators to factor the cost of testing into their offers. (See “Plan: Continue Cold Weather Testing, End Compensation for CP Participants,” PJM Operating Committee Briefs.)

All units will be required to be Capacity Performance beginning in the 2020/21 delivery year.

There were no other changes recommended for the program, which Schweizer said was valuable even though it didn’t yield much useful data last winter because of warmer temperatures.

Several members representing generation said the testing program will be a tough sell absent compensation.

“Without compensation, the program will dry up,” said one stakeholder who asked not to be identified.

John Farber of the Delaware Public Service Commission supported the plan.

“Customers are paying for premium capacity. The question is if they’re getting it,” he said. “We support where PJM is going with this. We really think compensation should be covered through the CP offer.”

Committee Chair Mike Bryson said staff would incorporate members’ comments into revised manual language that will be brought to a first read in July.

PJM Won’t Ask FERC to Rehear Ramp Rate Proposal, Plans to Collect Data

PJM will not ask FERC for a rehearing of its performance assessment hour (PAH) ramp rate proposal, which the commission rejected on May 31. (See FERC Rejects Ramp Rate Exception in PJM Capacity Rules.)

The Tariff changes would have exempted a capacity resource from nonperformance charges if it was following PJM’s dispatch instructions and operating at an acceptable ramp rate during periods of high load. They were drafted as a temporary measure to guard against generators self-scheduling prior to a PAH.

“As of right now, it’s status quo,” said PJM’s Rebecca Stadelmeyer, who convened a number of lengthy discussions over the past few months to win stakeholder consensus. “You need to be at expected Capacity Performance immediately.”

“We have decided internally that we’re not going to request a rehearing, largely because we took a good look at the arguments using examples we had from stakeholder endorsement,” Bryson said. “I think data is the next cog in getting this done. We’ll continue to collect that. I don’t know if we necessarily need an emergency situation to get all the data, though a performance assessment hour would help.”

Stu Bresler, senior vice president for operation and markets, agreed.

“We were disappointed that FERC didn’t take our word for it, but it seems the only thing that will change their minds at this point is data,” he said.

GOs to be Questioned on Governor Response Survey Results

PJM is concerned that most units participating in PJM’s Governor Response Survey did not provide reasons for deviating from NERC settings.

Schweizer said staff would be reaching out to generation operators to better understand the survey results, including why 5% of units didn’t participate.

Of those responding, 76% reported they had a governor capable of changing output in response to changes in interconnection frequency; 69% said their governor was operational; and 53% responded that their governor was capable of operating with the settings recommended by NERC.

About 43% of combustion turbines, 29% of combined cycle units and 24% of steam/fossil units reported they were capable of providing frequency response in accordance with NERC guidelines. Only 8% of hydro units and 1% of nuclear units reported such capability.

Two-thirds of the units did not provide a reason for deviation from NERC settings.

Among the reasons reported: control mode does not allow (10%); did not align with NERC-recommended dead-band (9%); and set with a slightly less droop setting of 4% (5%).

— Suzanne Herel

June 13, 2016

Lawyers Take an Economics Class: Capacity Markets vs. Scarcity Pricing

By Rich Heidorn Jr.

WASHINGTON — Four Ph.Ds. joined in a tag-team debate last week on the virtues of scarcity pricing versus capacity markets in a panel discussion-cum-economics seminar at the Energy Bar Association’s Annual Meeting.

William Hogan, Harvard — Hogan © *RTO Insider*

It’s unlikely any of the combatants, who have often sparred each other, came away with any different opinions. But the repartee was no less sharp for the familiarity.

William W. Hogan, research director of the Harvard Electricity Policy Group, staked out the energy market-only pole of the debate, repeating his argument that capacity markets are unnecessary if the energy and ancillary services markets “get their prices right.”

“Life is too short to spend your time trying to perfect capacity markets,” Hogan said.

PJM Market Monitor Joe Bowring said Hogan’s vision is unrealistic. “It’s easy enough to say in a theoretical world that scarcity pricing should take care of everything. But we have yet to see that demonstrated in the real world,” he said.

Administrative Determinations

Bowring also attempted to puncture any notion that scarcity pricing is much simpler than capacity markets.

“Let’s not pretend that scarcity pricing is some automatic market mechanism that will simply take care of problems without an intervention,” he said. “It is equally administrative as capacity markets — just different. You still have to determine … the appropriate net revenue. And it’s a lot trickier than it sounds.”

Sam Newell, a principal with The Brattle Group, challenged Bowring’s assertion.

“Although the pricing in an operating reserve demand curve [ORDC] is administratively determined, actually there’s less administrative determinations than in a capacity market because you’re just saying what the prices should go to under certain real-time operating conditions.”

In a capacity market, he continued, “You have to decide what is the reliability concept you’re meeting. Is it summer peak? … You have to decide how different resources can qualify to meet that and so there’s a lot more administrative determinations.”

Concern over Volatility of Revenue Stream

Sam Newell, Brattle — Newell © *RTO Insider*

David Patton, whose Potomac Economics provides monitoring services in MISO, ISO-NE, NYISO and ERCOT, expressed concern over the volatility of generators’ revenue streams under scarcity pricing.

“Unless you’re willing to price shortages at $200,000/MWh, you’re not going to meet your planning requirements with the energy market alone,” he said.

“Shortage pricing is not like a capacity market where you’re going to get a level of revenue that might fluctuate by 10 to 20% a year. With shortage pricing, you might get 10 years of revenue in one year and then the other nine years the generators are going to think they’re going bankrupt.”

This is because shortage prices “increase exponentially when you get unusually hot weather and unusually high loads or unusually poor generator performance,” Patton said. “Look at ERCOT in 2011 and compare the number of shortage incidents you had in that year to the prior 20 years.”

That could lead to constant tinkering, Patton said. “You don’t want policymakers to jump in when it’s not producing revenues for a number of years. You also don’t want them to jump in in the year when it produces $20 billion of revenue,” he said. “Because that’s what you signed up for.”

Bowring added another potential negative consequence.

“What will happen if you go through eight years of very low revenues under scarcity pricing … and a significant number of units decide to retire because they can’t see into the future? They don’t know if [in] the ninth or 10th year there’s going to be $20 billion. They retire if the revenues aren’t adequate.

“There’s a level of risk associated with scarcity pricing that differs from capacity markets, which is why the optimum might be to have more revenues in the scarcity pricing but not 100% of expected revenues,” Bowring said.

Locational Issues

Bowring said he agreed with the need for scarcity pricing but said it “is done very ineffectively now” in PJM because the ORDC hasn’t been made “adequately locational.”

“Scarcity doesn’t work if it’s an aggregate, because you can be long aggregate in PJM or other big RTOs or ISOs and be very short in particular places,” he said.

Joint Optimization

ERCOT has a different problem, said Patton: a failure to jointly optimize the energy and shortage markets so that the ISO can price transitory shortages.

“We perpetually undercompensate units like pump storage units, combined cycle units. They’re way more valuable for reliability because they can ramp fast,” he said. “But if you don’t reveal the true state of the system in every five minutes you undercompensate them.”

Market Mitigation

David Patton, Potomac Economics — Patton © *RTO Insider*

Hogan sought to allay what he called a misconception that shortage pricing is incompatible with price caps and other market mitigation measures.

“The advantage of this operating reserve demand curve … is that prices go up because of the scarcity of reserves. They don’t go up necessarily because of high offers by the generators. So it is completely compatible to have offer caps — which are dealing with market power problems with generators — that are set by their variable cost of operation. You could have a $500 offer cap, say, on generators and then you have the operating reserve demand curve that is setting the price and the price is $3,000/MWh.

“All of the market mitigation … continue to exist. You don’t have to get rid of that,” he continued. “If you don’t have the operating reserve demand curve, offer caps depress the price and do all kinds of bad things.”

Changing Conditions

Newell said scarcity pricing may be better suited to respond to changes facing the industry.

“With variable energy resources suppressing energy prices — creating over-generation sometimes on the one hand, ramping shortages on the other — the nature of reliability is changing, and it’s not just about summer peak.

“And that is another reason why I want to second what Dr. Hogan said. It is better to get the prices right — reflecting real-time conditions and telling the market what you need, when you need it — rather than just having a narrow administrative idea of reliability. So I would like to see more money moving into the energy and ancillary services markets and out of the capacity markets.”

June 13, 2016

PJM Planning Committee TEAC Briefs

Planners are sticking with their decision to recommend that the PJM Board of Managers approve a $340.6 million market efficiency project to address congestion at the AP South interface.

Since last month, when PJM told the Transmission Expansion Advisory Committee of its intention to back the proposal, planners have conducted additional sensitivity studies on the selected project using lower gas prices. They did not perform additional studies on three competing proposals. (See “Planners Choose Project to Relieve APSouth Congestion,” PJM Planning Committee and TEAC Briefs.)

Project 9A (without capacitors), submitted by Dominion High Voltage and Transource Energy, performed even better at providing production cost savings with low gas inputs, PJM said.

LS Power’s Sharon Segner continued to object to the project being chosen without further study of the three cheaper competing proposals. They ranged from $72 million to $253 million.

For one thing, she said, there was no carbon pricing in the model, so the project is being approved as if the Clean Power Plan, currently stayed by the Supreme Court, will not be implemented.

“Basically, you’re approving the project based on a zero-carbon pricing model in the non-[Regional Greenhouse Gas Initiative] states,” she said. “If you had carbon pricing in the model, project 9A would look different, and competing projects would be different.”

Given the cost of the project, she added, it should be tied to cost caps.

A letter to the TEAC from LS Power’s Northeast Transmission Development expounded on her concerns. Another letter echoed her complaints regarding the carbon pricing assumptions.

“We’ll take a closer look at the operating agreement,” responded TEAC Chair Paul McGlynn. “We’ve certainly done a lot of studies and sensitivities under a number of variables. We think we are satisfying the requirements of the Operating Agreement.”

The expected in-service date is 2020.

PJM to Open FERC Order 1000 Proposal Window in Late June

PJM expects to open its second 2016 Regional Transmission Expansion Plan window in the last week of June, McGlynn said.

Its scope will consist of a year 2021 analysis of N-1 and N-1-1 thermal and voltage contingencies; generation deliverability and common mode outages; and load deliverability thermal and voltage.

Newark Airport’s Increased Energy Need May Spark Reliability Violation

Newark Liberty International Airport has identified a need for additional energy resources. Its current load is about 40 MVA, but a new planned terminal is expected to increase that load by about 33 MVA.

Meanwhile, the Port Authority of New York and New Jersey’s future plans for its PATH rail line are anticipated to add another 8 MVA for a total of 81 MVA.

The airport’s energy needs are expected to increase further with planned upgrades to Terminal B and Terminal C.

PJM Planning Committee, Transmission Expansion Advisory Committee — Newark Airport *Source: Newark Liberty International Airport*

The facility’s load will be served by two new 345-kV underground cable circuits, part of the Bergen-Linden Corridor project. Existing 26-kV circuits will be used for backup.

However, that presents a potential reliability violation, because a portion of the 26-kV station property is owned by the airport, and it has requested the use of the land back. In addition, the 26-kV facilities are aging and potentially thermally overloaded.

Artificial Island Project Alternatives, Cost Continue to be Studied

PJM and Public Service Electric and Gas are continuing to look at ways to reduce the cost of the Artificial Island stability fix, including moving the 230-kV line to Hope Creek instead of the Salem substation.

“Cost estimates are being developed for the new configuration,” McGlynn said. “We are looking at it from a scheduling perspective as well — what potential impact it may have on changing the design of the project. There is also ongoing work relating to analytical work and stability studies.” (See Artificial Island Cost Increase Could Lead to Rebid.)

Installed Reserve Margin Study Assumptions Endorsed

The Planning Committee endorsed the 2016 installed reserve margin (IRM) study assumptions developed by the Resource Adequacy Analysis Subcommittee.

The recommendation retains the current load model selection process with one minor change: clarifying that the annual peak can only be drawn from the summer peak week. (See “IRM Assumptions Presented for First Read,” PJM Planning Committee and TEAC Briefs.)

PJM’s Tom Falin said that had the change been implemented for last year, the same load model would have been selected, and the IRM would have been the same.

Planners also will continue to model a 2.5-GW ambient derating for the summer.

PJM Beefing up Details of TO Upgrade Exemption Proposal

PJM staff is adding more details to its plan to exclude typical transmission substation equipment from competitive windows as a result of questions that FERC had regarding the RTO’s proposal to exclude some low-voltage projects from the process. The commission responded to PJM’s voltage floor proposal with a May 27 deficiency notice ordering the RTO to provide additional information (ER16-1335).

“With this process, it’s going to be similar [to the voltage floor proposal] because we’re basically excluding problems that we think will result in a transmission owner upgrade,” PJM’s Mark Sims said. “If [FERC] had concerns with the voltage floor, they probably would have concerns with this.” (See “Typical TO Upgrades Would be Excluded from Competitive Window under Proposal,” PJM Planning and TEAC Briefs.)

Among FERC’s concerns was how stakeholders could comment on exempted projects. PJM’s Sue Glatz said the RTO is drafting a compliance filing to FERC due at the end of the month regarding the voltage floor exemption.

The PC will be asked to endorse the TO upgrade exemption next month.

80% of Projects Submitted in Past 6 Months Wouldn’t Meet New Procedures

About 80% of the projects submitted to the proposal queue would have been bumped if new submittal procedures had been in place, PJM’s Dave Egan said in his semiannual update of the project queue. (See “Stricter Rules Proposed for Queue Submittal Process,” PJM Planning Committee and TEAC Briefs.)

More than half of the projects for the six-month queue were submitted on the last day, he said.

He noted there has been an uptick in solar projects in Virginia and North Carolina and a slight reduction overall in natural gas.

Task Force Breaks into Subgroups to Study Minimum Design Standards

The Designated Entity Design Senior Task Force, created to draft minimum design requirements for competitively solicited facilities, has divided into three subgroups to focus on transmission lines, substations and system protection, and control design and coordination. (See “Task Force will Create Design Standards for Competitive Projects,” PJM Planning Committee and TEAC Briefs.)

The protection subgroup has determined that Manual M7 is a good starting point but will be examining additional items, including metering requirements, commissioning procedures and disturbance monitoring equipment.

The main focus of the substation subgroup will be different voltages, criteria-based design, functional layout, future expansion and minimum outages.

The task force expects to deliver its recommendations to the PC in September.

Network Upgrade Cost Allocation Process Hits a Snag

PJM is studying issues it has identified with the network upgrade cost allocation process for new service queue requests.

PJM’s Aaron Berner explained that in studying the need for projects, customers are evaluated together. But when it comes to allocating the cost of approved projects, transmission service customers aren’t allowed to share costs with the other customers.

“Everybody is studied together. Then we come to the point in the Tariff that discusses cost allocation as opposed to mechanics. We then cannot allocate cost to transmission service customers,” he said.

He expects to return next month with a draft problem statement to address the issue.

– Suzanne Herel

June 10, 2016

OMS-MISO Survey: Generation Shortfall Possible

By Amanda Durish Cook

Plant retirements could cause a generation shortfall in MISO as early as 2018, two years earlier than previously expected, according to the RTO’s 2016 survey with the Organization of MISO States.

The survey, released Friday by MISO and OMS, forecasts a narrow surplus in 2017 but concludes that “action is required in the near term to ensure sufficient resources in future years.”

For 2017, MISO is forecast to exceed the projected 15.2% reserve requirement by 0.9 GW (0.7% above the requirement), although multiple zones will be below their resource requirement and will have to rely on imports. Southern Illinois’ Zone 4 could have a 0.5-GW surplus or a deficit as large as 1.2 GW. Zone 5 in Missouri is forecasted to have a 0.8-GW deficit, and Zone 7 in Lower Michigan could have 0.3-GW shortfall.

By 2018, the survey says, MISO will face a 0.4-GW shortfall if no “low certainty” generation — projects in the interconnection queue that have not signed interconnection agreements — are completed. Under the same worst-case scenario, the gap rises to 0.5 GW in 2019, 1.9 GW in 2020 and 2.6 GW in 2021.

Half of MISO zones are predicted to experience a shortfall by 2021, with only the Dakotas (Zone 1), Wisconsin and Upper Michigan (Zone 2) and MISO South (zones 8, 9 and 10) showing sufficient capacity. Zone 4 could have the largest shortage at 1.7 GW.

Under a best-case scenario that assumes all low-certainty resources go into commercial operation, the 15.2% planning reserve margin could be met throughout 2018-2021, reaching 16.9% in 2018, 17.1% in 2019, 16.1% in 2020 and 15.5% in 2021.

Worsening Forecast

Last year’s survey predicted a 2.6-GW regional surplus in 2017, a 1.7- to 2.3-GW regional surplus in 2016 and a deficit by 2020. (See MISO Survey: No Shortfall Until 2020.)

Jennifer Curran, MISO vice president of system planning and seams administration, said the worsening forecast resulted solely from increased retirements, including those in Southern Illinois. (See Dynegy to Shutter 3 Ill. Coal Plants; Blames MISO Market Design.) The new survey appeared to be on track with last year’s forecast, pegging the 2017 regional surplus at 2.7 GW, but calculations were adjusted to reflect recently announced retirements.

According to MISO staff, the survey took into account all recently announced retirements, including DTE Energy’s planned retirement of eight coal-fired units in Michigan beginning in 2020 and the 2017 closure of Exelon’s Clinton Nuclear Generating Station in Illinois. For the first time, the survey included merchant generators in addition to load-serving entities.

Time to Get to Work

During a Friday conference call, both Curran and Sally Talberg, OMS president and chair of the Michigan Public Service Commission, stressed that state officials and regulators and load-serving entities should be working on resource adequacy plans.

“I would note that the load-serving entities in Zone 4 can take action any time using bilateral contracts,” said Curran, who also noted MISO’s plan to change the capacity auction design for the zone. (See MISO Moves Forward on Auction Design; Seasonal Filing Delayed Again.)

“This is a crucial period given the amount of resources that have retired and will retire during the survey horizon,” Talberg said.

MISO CEO John Bear said the RTO will continue to support “state regulators and members as they take necessary actions to ensure continued resource adequacy in 2018 and beyond.”

Curran said MISO’s flood of retirements is partially offset by lower demand, but that retirements are still outpacing new resource additions. She said while the number of projects in the generator interconnection queue has increased, the number of projects that complete the process and begin producing power “has remained flat.” For 2017, the survey predicted 0.7 GW of high-certainty new resource additions.

“Firming up those planned generation interconnections is going to be important,” Curran added.

In 2017, the survey shows zonal transfer limitations keep some projected capacity from serving load elsewhere. Curran said the constraints in Zone 1 are being addressed with transmission construction and that MISO is in talks to identify a solution to the transfer limits between the North and South regions.

Disparity

During the conference call, multiple stakeholders questioned the survey’s forecast, asking why the capacity auction results showed a larger surplus than the survey results for the second year in a row. (See MISO’s 4th Capacity Auction Results in Disparity.)

“It’s a survey and we have made certain assumptions,” Curran responded. “This is a reflection of 2017, not the current year auction results.” She said the survey is not the “end-all, be-all” in future capacity.

MISO plans to hold a detailed breakdown of survey results at the June 29 Resource Adequacy Subcommittee meeting.

June 8, 2016

ERCOT IMM: Low Gas Prices Reduce Costs, Revenue

By Tom Kleckner

ERCOT’s Independent Market Monitor said the market “performed competitively” in 2015, with low natural gas prices helping reduce energy costs and congestion revenue to record lows.

Potomac Economics’ annual State of the Market report, filed with ERCOT and the Public Utility Commission of Texas, said the ISO’s average real-time energy price fell 34% last year to $26.77/MWh, eclipsing 2012’s prices ($28.33/MWh) as the lowest annual energy cost since the nodal market came online in December 2010.

The drop was fueled by average natural gas prices 41% lower in 2015 than 2014, falling from $4.32/MMBtu to $2.57/MMBtu. The Monitor said the correlation between gas prices and energy costs is to be expected in a “well-functioning, competitive market,” as “fuel costs represent the majority of most suppliers’ marginal production costs.”

“Suppliers in a competitive market have an incentive to offer supply at marginal costs and natural gas is the most widely used fuel in ERCOT,” the Monitor said.

Lower gas prices also contributed to a $352 million decrease in congestion revenue, down 50% from 2014’s record $704 million, despite a similar number of binding constraints as the year before. The total was more than $100 million lower than the previous low for congestion costs.

“This is largely due [to] the significant reduction in natural gas prices and the cumulative benefits of large investments in transmission facilities,” the Monitor said, noting gas units are typically re-dispatched to manage system flows.

The report also indicates ERCOT’s average real-time load was up 2.4% from 2014 — the ISO set a new hourly demand record of 69,877 MW on Aug. 10 — but that shortages were “rare” and planning reserves were above the minimum requirement. However, the Monitor said the market’s net revenues were less than the amount needed to support construction of new gas units. It calculated net revenue for new gas turbines last year at $23 to $29/kW-year, far below the necessary $80 to $95/kW-year.

The Monitor found both nuclear and coal units to be money losers in 2015. The ISO’s four nuclear units’ generation-weighted average price was $24.56/MWh in 2015, compared to the Nuclear Energy Institute’s estimated operating costs of $27.53/MWh last year. Coal and lignite units averaged $25.94/MWh prices, compared with the Monitor’s assumed fuel-only operating costs of approximately $30/MWh.

“This is significant because the retirement or suspended operation of some of these units could cause ERCOT’s capacity margin to fall below the minimum target more quickly than anticipated,” the Monitor said. It currently predicts ERCOT’s reserve margin will stay above its 13.75% target “for the next several years.”

The Monitor acknowledged ERCOT made several improvements to its market in 2015 in response to its recommendations, but it said three suggestions from last year have yet to be addressed. It recommends ERCOT:

Implement real-time co-optimization of energy and ancillary services;
Modify the real-time market software to better commit load and generation resources that can be online within 30 minutes; and
Price future ancillary services based on the shadow price — the system cost for the last megawatt of load — of procuring the service.

The Monitor also said the PUC should evaluate policies that create incentives for loads to reduce consumption for reasons unrelated to real-time energy prices, including the need for emergency response service (ERS) and the allocation of transmission costs. It said the “lucrative” ERS program limits the motivation for loads to participate and contribute to load formation in the real-time market, while rising transmission costs “significantly” increase the already substantial incentive to reduce load during the summer season’s probable peak intervals.

“Both of these mechanisms provide strong incentives for load to act in ways that are not aligned with the most efficient electricity market outcomes,” the Monitor said, “which are to ensure that the price continually reflects both the cost to provide (supply) and the value to consume (demand).”

June 6, 2016

Constitution Asks FERC to Dismiss New York Complaint

Constitution Pipeline asked FERC on Thursday to dismiss a complaint by New York’s attorney general alleging illegal tree cutting, requesting fast-track resolution to the ongoing dispute over the proposed 124-mile natural gas project (CP13-499).

The company vehemently denied allegations made by Attorney General Eric Schneiderman that it encouraged illegal tree cutting by landowners in defiance of a FERC prohibition, calling the complaint “part of a pattern seeking to delay construction.”

“The complaint does not contain any evidence that ‘clear-cutting’ … has occurred or, if it did occur, that it was performed or caused by Constitution,” the company wrote. “Instead, the complaint merely contains vague allegations that landowners or the landowners’ logging companies, against whom the attorney general seeks no enforcement action, conducted tree clearing, road building or other ground disturbing activity on the pipeline right of way in New York, in 10 locations [that] the attorney general refuses to, and fails to, describe with any specificity sufficient to actually identify any of them.”

Constitution said the vagueness of the attorney general’s complaint required that FERC appoint an administrative law judge to develop a complete record. It also said that fast-track processing was necessary because the complaint alleged ongoing violations of federal law.

Schneiderman wants FERC to investigate the company and assess it fines. (See New York Demands Probe of Tree Cutting on Pipeline Route.)

The pipeline is intended to bring shale gas from the Marcellus region of Pennsylvania into the New York and New England markets.

In April, the New York Department of Environmental Conservation denied Constitution a water quality permit under Section 401 of the federal Clean Water Act. Constitution last month appealed the permit denial in federal court. (See Constitution Pipeline Appeals Rejection of Water Permit.)

– William Opalka

June 6, 2016

MISO Moves Forward on Auction Design; Seasonal Filing Delayed Again

By Amanda Durish Cook

MISO said last week it will not yield on a planned July filing for capacity auction changes in deregulated areas, but a filing to add seasonal and locational constructs will be delayed until later this year.

During a two-day meeting of the Resource Adequacy Subcommittee, Jeff Bladen, executive director of MISO market services, said the July 15 filing goal for a new auction design is unchanged and draft Tariff language will be in front of stakeholders in time for a special meeting of the RASC on June 13.

The Tariff filing planned for next month would introduce a bifurcated procurement using both the existing Planning Reserve Auction and a separate three-year forward model for deregulated areas that would use a sloped demand curve. MISO will allow regulated demand to voluntarily participate in the forward auction, but not regulated supply.

The RTO released business rules and an updated work plan on its proposal and has retained The Brattle Group to review it.

Bladen also addressed disagreements between MISO and the Independent Market Monitor over the proposed changes, saying the RTO was working to “close the gap.”

“I wouldn’t describe it as ‘at odds,’” Bladen said of the opposing viewpoints. “There’s a philosophical difference in how a sloping demand curve would be applied. We’re trying not to place any new rules on nonparticipating states.”

Last month, the MISO Board of Directors ordered the RTO and Monitor to negotiate their differences in a joint work session. (See MISO Board Orders Negotiation in Longtime Auction Disagreement.)

“This isn’t a summit meeting of Cold War adversaries,” Bladen reassured stakeholders. “MISO meets with the IMM regularly, and there are discussions between MISO and [Monitor David] Patton and his staff almost every day.”

Bladen conceded that if the talks result in major changes to the design construct, the July filing timeline would be “very hard” to accomplish.

Bill Booth of the Mississippi Public Service Commission asked what changes might result from the talks.

“I certainly wish I had an answer on what a compromise is going to look like, but we’re going to work through it … and find common ground,” Bladen said.

Other stakeholders repeated a desire for more time to review simulation results and vet Tariff language.

“We understand where your intentions are, but there are some that think the competitive retail solution isn’t necessary, and there’s a lot of work to be done in the Business Practice Manuals. I think the July Tariff filing is overly ambitious,” said Jim Dauphinais, counsel for Illinois Industrial Energy Consumers.

NRG Energy’s Tia Elliott asked if MISO would have a third party critique the Monitor’s proposed solution as well as the RTO’s. Bladen said that could be done.

MISO released 17 pages of business rules last week based on the prior presentations and asked for stakeholder response by June 8 so input could shape draft Tariff language, which is due in time for the June 13 special meeting of the RASC. Subcommittee liaison Renuka Chatterjee said the rules could be made into a new Business Practices Manual or inserted into existing BPM 11, which governs the Planning Resource Auction (PRA).

“This is very much a first draft,” Dauphinais said of the business rules document, pointing out that a demand curve shape hasn’t yet been settled on. “We’re concerned you’re not prepared to put out Tariff language on June 8.”

“I’ve heard a lot of opposition, but I haven’t heard a lot of support,” added Booth.

“Nothing is ever not contested at FERC,” Chatterjee offered in response.

MISO capacity auction design — A filing to implement external resource zones in addition to MISO’s existing local resource zones (pictured above) and a two-season capacity construct will be delayed until the fall as the RTO gathers more information from stakeholders.

Chatterjee outlined the work plan:

June-July: Rewrite Tariff and BPM language
July-January: Software development
October-February: Internal and external auction training
March: Launch (for 2017/18 planning year)

Study to Delay Seasonal, Locational Construct

While pushing ahead on the auction design, MISO has abandoned the July filing goal of seasonal and locational constructs and promised stakeholders an additional two months for the concepts to be vetted through the RASC. The delay will allow completion of a new seasonal loss-of-load expectation (LOLE) study and continuing talks on dividing capacity accreditation into winter and summer, according to MISO’s Laura Rauch.

The study will explore how lower capacity reserve margins in the winter would affect seasonal capacity accreditation and how separate summer and winter LOLEs would impact capacity import/export limits and planning reserve margins. Rauch said MISO does not expect to have specific numbers on transfer capabilities and seasonal reserve margins until the fall.

Rauch also said more time is needed to consider definitions of external resource zones.

“We don’t want to put a hard and fast timeline on this. Once we resolved these concerns, we will file, but we do want to file this year,” Rauch said. Pressed by stakeholders, she said MISO is envisioning a September filing but would make an October filing if discussion or study findings warranted postponement.

“We’ve had three filings dates out there, and we don’t want to keep moving things around,” Chatterjee added.

Rauch said an open question is how MISO should define forced outage rates and planned outage hours during critical hours: weekday hours ending 15, 16 and 17 during June, July and August; and weekday hours ending 9, 19 and 20 during December, January and February.

Rauch said a seasonal capacity accreditation process would begin next June.

Even with the seasonal and locational constructs paused for discussion, stakeholders were wary.

“I get the impression MISO just wants time to explain this better, but there’s opposition because other alternatives exist,” Customized Energy Solutions’ David Sapper said.

Dynegy’s Mark Volpe also said stakeholders don’t want to spend the next two months sounding like a “broken record” on recommendations.

Both Chatterjee and Rauch said MISO staff would take time to respond to new questions and recommendations in the coming weeks.

Monitor Outlines Approach on Avoidable Costs

Meanwhile, Market Monitor Michael Chiasson outlined an approach that relies heavily on PJM to develop default technology-specific avoidable costs for future PRAs. FERC mandated the defaults in its New Year’s Eve order to lessen the burden of verifying reference levels on a unit-by-unit basis (EL15-70 et al.).

A compliance filing is due June 28. Chiasson asked for stakeholder input in time for another review of draft Tariff language during the June 13 RASC conference call.

MISO and the Monitor agree that the RTO should use PJM default values for the 2017/18 planning year but without PJM’s 10% adder. Chiasson said MISO doesn’t have enough time to survey generators to develop its own default values before next year’s auction.

“The June 28 compliance filing deadline makes it unlikely that a MISO survey would receive a sufficient number of responses to produce representative results for the various technology types,” the Monitor explained. However, the Monitor said it would “consider expanding the IMM’s operating cost survey so the default values can be based on MISO participant data in future years.”

Because PJM doesn’t develop default values for nuclear and wind units, the Monitor is proposing a wind avoidable cost of $108.30/MW-day based on Energy Information Administration data and a nuclear avoidable cost of $454.79/MW-day based on a recent white paper by the Nuclear Energy Institute.

For all the avoidable cost values, the Monitor suggested using the monthly Consumer Price Index to update values. Chiasson said the Monitor considered using other indices that track power production costs, but they were either overly reliant on capital costs versus operations and maintenance expenses, their values were too volatile or the reports weren’t produced often enough. For planning years beginning more than six months after the latest CPI is released, the Monitor recommended using a 10-year average of CPI changes to escalate prices an additional year.

Dauphinais asked for more evidence supporting use of the PJM default values. “We’re very anxious to get those,” he said. “We’re missing some data here.” Chiasson said the Monitor would provide more information on PJM values at the next RASC meeting.

June 6, 2016

Company Briefs

Dynegy has closed its 500-MW Wood River Power Station near Alton, Ill., eliminating more than 90 jobs.

Company officials announced plans to close the coal-fired plant in November after it failed to recover operating costs. The utility cited unfair market conditions in the deregulated and regulated hybrid footprint in MISO. Dynegy also said Wood River was not necessary to maintain reliability in the region.

In addition to $12 million in lost pay for the workforce, the closure will cost the local government $1.6 million in lost property taxes.

More: The Telegraph

Appalachian Power Enters PPA with NextEra Wind Farm

American Electric Power’s Appalachian Power has signed on to a 20-year power purchase agreement with NextEra Energy to buy 120 MW of wind generation in Indiana to supply its service areas in Virginia and West Virginia by 2018.

The wind power will come from the Bluff Point Wind Energy Center to be constructed in Jay and Randolph counties in Indiana. The company selected NexEra’s proposal over a dozen other bids.

The agreement brings Appalachian Power’s total wind portfolio to 495 MW.

More: Appalachian Power

CIO Cavazos Leaving DTE for Investment Firm

DTE Energy Chief Investment Officer Paul Cavazos is leaving his position at the diversified energy company to join Texas-based American Beacon, an investment firm specializing in mutual funds and corporate pension plans.

Cavazos worked at DTE Energy for nearly nine years, managing about $10 billion in investments, including benefit and contribution plans, a foundation and a nuclear decommissioning trust.

More: Chief Investment Officer

Alliant Treasurer Kratchmer Announces Retirement

Alliant Energy Vice President and Treasurer John Kratchmer announced plans to retire last week.

Robert Durian, Alliant’s current controller, will take over Kratchmer’s duties July 1. Kratchmer will serve in an advisory role during a transition period, according to the company. Durian has been with the company since 1992.

Alliant Assistant Controller Ben Bilitz will fill the position of controller.

More: Alliant Energy

Broadwind Signs $137M Manufacturing Contract

Wind turbine manufacturer Broadwind Energy has been awarded a three-year $137 million supply deal with an unnamed customer.

Broadwind, which has factories in Manitowoc, Wis., and Abilene, Texas, would say only that its customer is one of the largest wind turbine manufacturers in the U.S. Siemens and General Electric are among Broadwind’s major customers, according to a 2015 annual report.

More: Milwaukee Journal Sentinel

Thousands of PG&E Computers Left Vulnerable

Pacific Gas and Electric last month left a “treasure trove” of company data open to Internet hackers, according to a security researcher who revealed the lapse.

The compromised database contained company IP and MAC addresses, hostnames, computer locations and other vital information. More than 47,000 PG&E computers and other devices were left unprotected, the researcher said.

PG&E confirmed the lapse, blaming it on a third-party technology vendor that was developing a new platform.

More: Tech Insider

Municipal Utilities Sign Up with Grain Belt Express

The Missouri Joint Municipal Electric Utility Commission, which buys power for public utilities, said it has signed an agreement for as much as 200 MW of capacity on Clean Line’s Grain Belt Express, bolstering the transmission line’s embattled application with the Missouri Public Service Commission.

The new contract, which is contingent on Clean Line winning approval from Missouri regulators, would replace an electricity contract with Dynegy coal plants expiring in 2021, when Grain Belt is supposed to be operational.

The 780-mile transmission line would carry 3,500 MW of wind power from western Kansas to eastern markets and up to 500 MW of power into Missouri.

More: St. Louis Post-Dispatch

Keeping Westar’s HQ in Topeka Key to Great Plains’ Acquisition

Westar Energy CEO Mark Ruelle said Great Plains Energy was the only bidder among multiple suitors that agreed to keep the utility’s headquarters in downtown Topeka, Kan., one of the deciding factors in choosing it as its $8.6 billion merger partner.

Although an investor-owned company must first consider shareholder value, Ruelle said, Great Plains’ offer to stay true to Westar’s commitment to employees and its philanthropic efforts in the Topeka community weighed in its favor. The merger was announced May 31.

“It’s turned out that after all the work, the best deal is with our next door neighbors,” he said. “They’ve agreed to keep Westar headquarters in Topeka, and not only that, in downtown Topeka. Great Plains has agreed to continue our community commitments, our charitable giving, our connections downtown.”

More: The Topeka Capital-Journal

June 6, 2016

SPP Task Force Prepares to Hand off its Work

The SPP Capacity Margin Task Force conducted its penultimate meeting last week as it continues to set up the stakeholder group that will replace it in determining how low the RTO can go with its planning reserve margin.

The task force won board and member approval in April to lower SPP’s planning reserve margin — previously called the capacity margin — from 13.6% to 12%. The change is expected to save load-serving members about $86 million a year in capacity costs. (See “Lowered Reserve Margin Promises $86M in Annual Savings,” SPP Board of Directors Briefs.)

The CMTF will hold its last meeting June 30, turning over its work to the newly created Supply Adequacy Working Group (SAWG). The group will be responsible for developing and implementing processes that ensure “reliable supply of capacity necessary to meet demand and planning reserve margin requirements/methodologies in SPP.”

The SAWG will also be tasked with ensuring SPP’s processes and policies meet NERC and North American Energy Standards Board standards.

A separate small group is continuing its work on staff’s Resource Adequacy Workbook (RAW). The workbook will be used to gather load-serving entities’ planning reserve margin requirement calculations and data needed for the Energy Information Administration’s Form 411 (Coordinated Bulk Power Supply and Demand Program Report).

SPP’s vice president of engineering, Lanny Nickell, asked the task force for additional input on calculating planning reserve margin requirements for purchases and sales, which are calculated differently than they are for the EIA 411.

– Tom Kleckner

June 6, 2016

CAISO Floats Latest Cost Allocation Plan for Expanded Balancing Area

By Robert Mullin

CAISO is nearing completion of a proposal describing how the ISO would allocate the costs of building and operating transmission assets in an expanded balancing authority that could encompass areas of the West outside California.

The ISO considers development of a new transmission access charge (TAC) plan to be “a central policy element” of expanding into a region with dozens of balancing areas subject to multiple state and municipal rules determining compensation for transmission owners.

CAISO cost allocation plan, balancing area — CAISO’s potential expansion into the West is forcing the ISO to reconsider how it would allocate transmission costs across the region currently divided into multiple balancing areas.

Most pressing for CAISO: Development of new TAC options is essential for enabling Portland-based PacifiCorp to join an expanded system as early as next year.

‘Postage Stamp’ Rate

CAISO Principal of Market Infrastructure and Policy Lorenzo Kristov summed up the issue during a June 1 conference call to discuss the issue with Western industry participants: “The conversation we’re having here is — when you add new customers [to the ISO] — who would be paying for the service charge.”

CAISO currently uses a regional “postage stamp” rate to recover transmission revenue requirements for all ISO-controlled facilities rated at 200 kV or above. All internal load and exports are subject to per-megawatt-hour usage charges to fund those facilities.

Facilities rated below 200 kV and located inside the service territory of a participating transmission owner are covered by “local” rates paid by load within that territory. CAISO’s primary participating TOs are California’s three investor-owned utilities: Pacific Gas and Electric, Southern California Edison and San Diego Gas and Electric.

CAISO market participants are charged for transmission access based only on the regional or local criteria.

The current TAC makes no distinctions among projects driven by economic, public policy or reliability considerations, nor does it factor in-service dates or other non-voltage criteria.

“We’ve determined that the structure does need to be changed with an expansion,” Kristov said.

New ‘Sub-Regional’ Category

CAISO proposes to retain the category of regional — or ISO-wide — projects eligible for broad-based allocation, albeit in an altered format. At the same time, the ISO would introduce a new sub-regional category to accommodate TOs joining what could become a Western RTO in the future.

Under the latest TAC proposal, revenues for existing transmission facilities would only be eligible for recovery under “license plate” rates specific to each sub-region.

The upside for current CAISO members: They would not be charged for projects already operating in a new member’s service territory.

The downside: The sub-regional identification would also apply to CAISO’s current balancing area, meaning new members would not be assessed charges for California’s existing network.

The only projects eligible for regional cost allocation would be regional facilities approved under a new transmission planning process for an expanded ISO. To be considered for ISO-wide allocation, a proposed facility would be required to meet at least one of three criteria:

Having a voltage rating above 200 kV;
Facilitating interconnection — or increasing interconnection capacity — between two sub-regions; or
Creating, increasing or supporting the increase of intertie capacity between the expanded balancing area and a neighboring area.

Project Types

The TAC proposal would also introduce into the Tariff the practice of differentiating among different project types. For example, the new rules would make explicit that facilities approved to meet a reliability need within a sub-region would be allocated solely to that sub-region.

Economic and policy-driven projects would receive different — and more complex — treatment. Decisions regarding construction and cost allocation for those projects would be left to a new body of state regulators created in concert with the integration of a new TO into the ISO — an idea modeled on similar structures in ISO-NE and MISO.

“We know from precedent that agreement among the parties for cost allocation is important for FERC approval,” Kristov said.

CAISO is also considering additional provisions that would allow the expanded system to charge new TOs for costs of new regional facilities previously approved under the expanded transmission planning process. It would recalculate the sub-regional cost-benefit shares for those facilities at least every five years.

The ISO must also determine a regionwide export rate — or wheeling access charge — and develop FERC-required backstop provisions for approving and allocating costs for economic- and policy-driven projects.

“I just want to acknowledge that a lot in this proposal is not complete,” Kristov said.

Still, a draft final proposal for TAC options is slated to be released June 28. CAISO staff plans to present the plan to the ISO’s Board of Governors on Aug. 31.

Comments on the most recent proposal must be submitted to the ISO by June 10.