Page 1481 – RTO Insider

January 19, 2016

Markets and Operations Policy Committee Briefs

OKLAHOMA CITY — The Markets and Operations Policy Committee approved Tariff revisions that will set guidelines for distributing revenues from last year’s settlement with MISO over its use of SPP’s transmission grid. Three members opposed the Regional Tariff Working Group’s proposal and eight others abstained.

MISO has agreed to pay SPP and impacted members $9.6 million to settle claims for compensation dating back to 2014. (See SPP Board, Members Discuss MISO Settlement.)

The RTWG drafted language to handle revenues accrued during three phases (Jan. 29, 2014 to Jan. 31, 2016, Feb. 1, 2016 to Jan. 31, 2017, and each Feb. 1 to Jan. 31 period thereafter) and define how they will be collected and distributed.

It also revised other Tariff sections to take the new revenue distribution into account. SPP has said it favored allocating the funds to transmission owners, with benefits flowing through to the grid’s load.

Bill Grant of Xcel Energy opposed the request, saying the issue was not sufficiently vetted through the stakeholder process.

MOPC Endorses Recommendation to Pull Reliability NTCs; Other Projects, STEP Get OK

The MOPC unanimously endorsed staff’s recommendation to withdraw notifications to construct (NTC) for two reliability projects estimated to cost $40 million, including the South Shreveport-Wallace Lake 138-kV rebuild in northwestern Louisiana.

Antoine Lucas, SPP’s director of transmission planning, said the project was originally identified as a reliability need by SPP’s 2015 Integrated Transmission Plan 10-year assessment, but the 2016 ITP Near-Term assessment indicated the project is no longer necessary. It had an $18.6 million cost estimate.

SPP had also proposed the 11-mile project as an interregional project with MISO to meet economic needs, but MISO declined to support it. (See SPP, MISO Conclude Joint Study Empty-Handed.)

The 2016 ITPNT also showed there was no longer need for the Mineola-Grand Saline 69-kV rebuild in East Texas, estimated to cost almost $23 million.

“This project was primarily load driven,” said Midwest Energy’s Bill Dowling. “We really don’t think this is driven by dispatch of resources, but by load.”

Planners said further evaluation is necessary for two other projects, the $36 million Hobart-Roosevelt Tap-Snyder 69-kV rebuild in West Texas and the $7.1 million Linwood-South Shreveport 138-kV rebuild, because additional solutions for these needs were identified in the 2016 ITPNT.

American Electric Power was responsible for all four projects.

The committee also endorsed staff’s recommendation to move forward on two other projects. Members agreed (with six abstentions) no further re-evaluation was needed to construct a new 345/115-kV transformer and links to 345- and 115-kV lines at the Stevens County substation in southwestern Kansas, and agreed (with two abstentions) to remove conditions from an NTC that would provide fast-acting reactive power to a pair of 115-kV substations in southeastern New Mexico.

The Stevens County substation work is a joint project between Southwestern Public Service and Sunflower Electric Power, and has a projected $31.9 million cost, up from an original estimate of $18.3 million. Questioned on the costs, Lucas said the estimates “could be reduced once design work starts.”

The 111-kV China Draw-Road Runner projects belong to SPS. Despite an $84.8 million price tag, Lucas said the 2016 ITPNT indicates a need remains and it has been identified as the best solution.

“Once we re-evaluate a project and it’s still the right project, we recommend removing conditions,” Lucas said.

The MOPC also unanimously endorsed staff’s recommendation that the Board of Directors next week approve SPP’s 2016 Transmission Expansion Plan report (STEP), a comprehensive listing of all the RTO’s transmission projects over a 20-year planning horizon.

The 2016 STEP consists of 480 upgrades with a total cost of $6.1 billion. The projects include transmission-upgrade and generation-interconnection requests, approved high-priority upgrades and approved projects from the ITP 20-year, 10-year and near-term assessments.

Lucas said SPP members completed 93 transmission upgrades worth $856 million in 2015. He said the RTO also issued 50 NTCs for another $519.9 million worth of projects.

Staff will finalize its 2016 ITPNT this April and the 2017 ITP10 in January 2017.

MOPC Rejects Tariff Revision Allocating Manual Commitments

A Tariff revision to allocate the cost of manual commitments for voltage-related local reliability issues failed to receive approval from the MOPC. The measure, which would assess costs based on the asset owner’s impacted load, received only 41.3% approval from members, with 29 no votes and 17 abstentions.

“We’ve deviated from the philosophy of network load,” Xcel’s Grant said. “This whole discussion started with non-jurisdictional entities not solving the problem, but we went way further than we needed to go. It would be a disproportionate shift for New Mexico.”

Some members questioned whether SPP staff should have drafted the revision request and determined cost allocation in the first place.

“We as staff said one of our major principles is to take uplift and give it to the people who are causing it,” said SPP Executive Vice President and Chief Operating Officer Carl Monroe. “This is just another way to do that … and it’s going through the process. Don’t vote on this if you think it’s a short-term solution. It’s going to take a long time to get some of those things fixed.”

The committee endorsed two other revision requests from the Market Working Group, in addition to 12 others approved as part of the consent agenda:

RR 124, which adds language from the Tariff to the market protocols supporting SPP’s ability to reject incomplete market registration applications, was approved unanimously.
RR 127, approved with two no votes and four abstentions, eliminates the opportunity for jointly owned units (JOUs) to game make-whole payments by putting in a larger-than-normal energy offer curve and getting dispatched to minimum. For JOUs using the combined resource option, the rule takes all shares’ pricing points and aggregates them into one energy offer curve.

The MWG also shared its responses to nine recommendations by SPP’s Market Monitoring Unit to improve the Integrated Marketplace. Working with input from the MOPC leadership, the MWG developed an action plan on the Monitor’s recommendations in November for presentation to the Board of Directors next week.

The Monitor’s annual State of the Market report in July identified issues ranging from improving quick-start logic to market-power mitigation conduct thresholds. Several of the proposals have been implemented or are in process. (See SPP Monitor Report Shows ‘Maturing’ Integrated Marketplace.)

“We’re not saying [these recommendations solve] all of our problems, but [they do] a good effort moving everything forward we proposed,” said SPP’s MMU director, Alan McQueen.

‘Real Work’ to Begin on 2017 ITP10

Having completed a resource plan and a resource-siting plan, the working group developing the 2017 ITP10 will now begin building the economic model, assess constraints and do some benchmarking.

“Now the real work begins,” MOPC Chair Noman Williams said.

ITC Holdings’ Alan Myers, chair of the Economic Studies Working Group, said Clean Power Plan compliance will be a key part of the model. The group has developed three futures, two of which incorporate regional and state-level compliance and a third that assumes the CPP is not implemented.

“The ITP10 is the first salvo” in dealing with the CPP, Myers said. “I think we’re going to see more detailed studies.”

Reacting to concerns from Oklahoma Gas & Electric’s Greg McAuley that the resource plan didn’t include current load, Myers agreed the plan was a little out of date, having been developed and approved last year.

“The problem is if we do this over and over again, you never get to the finish line,” he said.

Myers shared the working group’s renewable and conventional resource siting plans as part of his informational update. He said the ESWG identified state mandates and goals, totaled what renewables were in place and then looked for gaps.

“It’s not actual shortfalls, but timing,” he said, noting some companies entered into new renewable contracts following the analysis.

Task Force Agrees on 18-month Planning Cycle, Common Model

The Transmission Planning Improvement Task Force said it has reached consensus on an 18-month planning cycle, a common planning model, a planning process and a standardized scope.

NextEra Energy Transmission’s Brian Gedrich, the task force chairman, told the MOPC the stakeholder process approvals and model development are bottlenecks and can limit the planning process’s frequency.

“The way the ITP20 is today, it doesn’t add value,” Gedrich said, pointing to “resource-intensive” work that provides “primarily strategic value, and not actionable results.”

Gedrich said the group has agreed on a strawman proposal that identifies the models that need to be built and removes near-term recommendations.

“The concern was the two-year economic assessment we’re moving to is much closer to what’s happening in real time,” he said.

The task force has scheduled a Feb. 3-4 meeting in Dallas, when staff is to unveil the final strawman, and an educational forum before the next MOPC meeting. The committee will then be asked to endorse the proposals to the board.

Task Force Continues Work on Improving Transparency

A task force working on improving transparency of members’ tariff-revision requests and proposing changes to SPP’s current prioritization processes updated the MOPC on its current progress.

The group is designing a structure in which members can submit revision requests and “enhancement” requests online through SPP’s Request Management System (RMS). (See “Prioritizing Revision Requests” in SPP Markets and Operations Committee Briefs.)

Staff prioritizes the requests in groups (in flight, primary, secondary, tertiary and other) before publishing them in a portfolio. Stakeholders can comment on the requests through the RMS and during quarterly stakeholder prioritization meetings one month before MOPC meetings.

Stakeholders can still request MOPC guidance and discussion on items of interest.

“When SPP staff puts in the time to explain issues, people may not realize that’s just starting the discussion. There’s no pre-determined outcome,” said SPP director Phyllis Bernard. “The board has been very encouraging in that [staff] get a strawman out, so we can have substantial conversations.”

“When we get on a call with stakeholders, they’re expressing their opinions and staff expresses their opinions,” Carl Monroe said. “MOPC becomes the appeals group for that.”

The task force received 68 comments during the comment period, and 38 stakeholders from 24 member organizations participated in the first quarterly prioritization meeting. That led to five action items for SPP staff.

The 2016 cycle begins Jan. 30, the deadline for submitting new enhancement requests. The next quarterly prioritization meeting will be held March 25.

Order 1000 Interregional Filing

SPP staff updated the MOPC on its failed attempt to create a new class of seams transmission projects, an effort to supplement its approved highway-byway cost allocation that was rejected by FERC on Nov. 30. (See FERC Rejects SPP Proposal for Seams Transmission Projects.)

At SPP MOPC: Richard Ross, AEP (© RTO Insider) — Ross, AEP (© RTO Insider)

“We had hoped by developing principles, we would avoid gaps,” said SPP’s Sam Loudenslager. “We realized there are still gaps in the process after the FERC order.”

“If FERC thinks … seams projects are already covered under Order 1000 compliance, do we have a problem?” Richard Ross of AEP asked.

“I think we do,” Loudenslager said. “Seams projects will not fit under the interregional process, where we do things on a project-by-project basis.”

“These projects come out of the joint operating agreement,” Monroe said. “It’s hard to take a project out of these other processes and use the Tariff to pay that through cost allocation.”

“We need a seams partner willing to look at these highway-byway projects,” said the Nebraska Public Power District’s Paul Malone. “MISO and [the Southeastern Regional Transmission Planning] don’t recognize these.”

Generation Group Recommends No Changes for Renewable Ratings

The Generation Working Group presented its bi-annual report on generating unit ratings, recommending no changes in the methodology for establishing wind and solar facilities’ net capability. Its report on summer 2015 looked at wind generation’s historical performance and commitment data from the Integrated Marketplace and compared generation-outage data to the previous summer season.

Noting the report’s information is compiled annually, AEP’s Ross wondered whether gathering the data every other year would suffice.

“There’s a lot of data that goes into this report,” said Mitch Williams of Western Farmers Electric Cooperative. “Doing this every year keeps it current.”

Violations Within SPP RE Drop into Double Digits

The SPP Regional Entity’s quarterly report revealed violations within the RE dropped below triple digits for the first time since 2009.

“The violations are less severe than they were a few years ago. Seventy-five percent of the issues … are someone being late turning something in or someone forgetting to sign a document,” the RE’s general manager, Ron Ciesiel, told members. “You’re helping by identifying issues before they fester and turning into real problems.”

The RE reported only 21 events in 2015, with just one reaching category 2 status and nine reaching category 1 status on a 5-point scale.

Ciesiel said critical cyber asset identification was the most frequent violation.

— Tom Kleckner

January 19, 2016

MISO Stakeholders Finish Governance Guide Changes

By Amanda Durish Cook

CARMEL, Ind. — The Stakeholder Governance Working Group sifted through the MISO governance guide paragraph by paragraph, refining priorities and committee hierarchies in the second of a two-day work session last Tuesday, part of the RTO’s stakeholder redesign.

The group doled out a draft of a redesigned pecking order for committees and their priorities. It also created assignment templates for groups that want to raise issues at meetings. MISO stakeholders will be required to complete an issue assignment template going forward for “ongoing issues with significant and substantial changes.”

Tia Elliott, director of regulatory affairs at NRG Energy, said the template will require members to clearly define their issue and explain what needs to be addressed instead of simply raising a hand at a meeting.

SGWG participants discuss governance (© RTO Insider)

MISO Stakeholder Relations Specialist Alison Lane expressed concern that anyone could identify an issue, meaning that stakeholders could spend time on issues of lower importance. “That’s the one thing that makes me really balk on this,” Lane said.

Under the proposed revisions, MISO would be required to announce meetings and post agendas and supporting documents “well in advance.”

Stakeholders said MISO also should limit the number of priorities it identifies in its annual strategic planning process.

“The ideal number of priorities is somewhere in the range of three to five to be effective. Too many priorities dilute the process and results in no real priorities being identified,” the SGWG wrote. The group added that stakeholder priorities should “reflect key elements of the MISO strategic priorities.”

The SGWG is also asking how MISO’s Advisory Committee can become involved in MISO’s annual discussion on priority setting. Stakeholders mulled over how often parent entities should review the status of their issue prioritization among themselves and the working groups and task teams they’re charged with, settling for now on a semi-annual schedule.

“This isn’t our last crack at it. We’ll do some more wordsmithing and get a clean version,” said Bill SeDoris, director of MISO integration for Northern Indiana Public Service Co.

The guide, now about 45 pages, includes new wording to provide for the review and “parking” of issues that haven’t been addressed by their due dates. New draft language also states that “major decisions” made by subordinate entities aren’t considered final until an Advisory Committee review.

At one point, Lane discouraged the group from including too many parliamentary procedure instructions in the guide, insisting that stakeholders should know how to conduct meetings.

“I just hate for us to put language in on Robert’s Rules of Order instead of good information on policy,” Lane said.

Greg Schaefer, energy market policy manager at MidAmerican Energy, said much was accomplished in the two-day policy review.

The revised governance guide will not be released publicly until it is presented at the Jan. 27 Steering Committee meeting. SeDoris said he also hopes to put the draft language before a vote at the Feb. 9 SGWG meeting, with final approval at February’s Advisory Committee meeting.

“I think status quo was clearly not working,” said WPPI Energy’s Valy Goepfrich of the old stakeholder process. She said it is up to stakeholders and MISO to ensure the changes streamline policymaking. “This is all going to happen again unless we follow this process.”

Elliott said the governance guide is often turned to in other MISO meetings to settle matters. “There’s a lot of value here,” she said.

January 19, 2016

Study: 60% Wind Penetration Possible in SPP

By Tom Kleckner

OKLAHOMA CITY — SPP could handle wind-penetration levels of up to 60% with additional transmission and monitoring tools, officials told the Markets and Operations Policy Committee last week.

The RTO’s first wind integration study since 2009 found that wind energy, which represented about 14% of system capacity at the end of 2015, will expand significantly based on requests in the interconnection queue. The study analyzed SPP’s transmission area for system reliability breakpoints due to increased wind generation and said additional operational procedures should be considered “to reliably operate above the currently installed maximum wind capability.”

If its recommendations are implemented, the report said, SPP’s transmission system could “reliably handle” wind representing up to 60% of internal SPP load. The RTO saw record wind-penetration levels last year approaching 39% and a record wind peak of 9,948 MW. (See SPP, ERCOT Set New Wind Peaks.)

SPP studied wind-penetration levels of 30%, 45% and 60%. A voltage-stability analysis indicated renewable penetration levels are approaching current limits. SPP also analyzed wind energy ramping, re-dispatch and outages and steady-state thermal and voltage.

“We’re at those levels where [previous] studies said we would start having issues,” said Casey Cathey, SPP’s manager of operations engineering analysis and support. “We could have situations where we hit 45% without reliability concerns, but is that for an hour or sustained?”

Cathey said SPP has 156 wind farms totaling 12,380 MW of installed capacity and will reach 16,960 MW of installed wind at the end of 2016. SPP projects at least 2,035 MW will be added in 2017.

The report calls for expediting transmission projects, noting that about half of the 4,580 MW of wind expected to be added this year will require new lines. It also shows the need for “some limitation before we can build out the system further,” Cathey said.

It also recommended installing voltage reactive support capabilities for existing wind farms; enhanced operations tools, to monitor real-time voltage stability limits; allowing the reliability coordinator additional flexibility in re-dispatching; new planning criteria for and evaluation of phasor measurement units to provide real-time situational awareness.

“It’s worthy to note SPP put a significant amount of wind growth in the system,” The Wind Coalition’s Steve Gaw said. “It’s working … we have high penetration with low loads, and we’ve been able to do that reliably.”

Cathey said SPP is “good at forecasting wind,” but that ramping issues take place in two- to three-hour timeframes, not five-minute intervals.

“We know it’s going to ramp,” he said, “but we don’t know when. We know it will happen in the morning, but we don’t know if it’s 6:30 or 7:30.”

Cathey said SPP is continuing to improve its weather forecasting, which is supplied by energy & meteo systems. MISO also uses energy & meteo.

SPP has scheduled a wind-integration summit Feb. 17-18 at its headquarters in Little Rock, Ark. Cathey said the summit will provide stakeholders an open forum to ask questions, provide feedback and critique the study’s results.

January 19, 2016

New York AG: No Tree Cutting for Pipeline Without Water Quality Permits

By William Opalka

New York Attorney General Eric Schneiderman asked FERC on Friday to prevent a natural gas pipeline developer from clearing trees along the route of one of its projects while water quality permits are pending (CP13-499).

Constitution Pipeline wants to build a 124-mile pipeline through New York to connect shale gas fields in Pennsylvania with markets further east.

“Since cutting down trees in the pipeline corridor constitutes construction, the [Office of Energy Projects] may not grant the request to proceed unless and until Constitution has obtained all of the authorizations required under federal law to construct the proposed pipeline,” Schneiderman wrote in his request for a stay.

The pipeline has all the necessary permits except for water quality certification under Section 401 of the U.S. Clean Water Act. That application is pending before the state Department of Environmental Conservation. The project would cross 220 bodies of water along its route, according to the attorney general.

Schneiderman said tree cutting would cause “irreversible alterations” to property before required permits are obtained.

Constitution told FERC in January 2015 that tree cutting must be conducted between Nov. 1 and March 31 to comply with U.S. Fish and Wildlife Service recommendations to mitigate impacts on migratory birds and the northern long-eared bat.

“Constitution is therefore requesting written authorization … to commence limited, non-mechanized tree felling activities necessary to comply with these conservation measures,” the company wrote to FERC.

The developer said it would use chainsaws to cut trees at or above ground level and would not disturb soils or root systems. It said it would leave the felled trees in place until other construction started.

FERC granted Constitution a certificate of public convenience and necessity in December 2014. The project has encountered fierce opposition from the group Stop the Pipeline, which cites environmental threats to streams, wetlands and forests along its route. (See Constitution Pipeline Opponents Asks Appeals Court to Force FERC Action.)

January 19, 2016

Entergy Disputes Investigation of Indian Point, Calls it Political

By William Opalka

Entergy wants state regulators to appoint an administrative law judge to counteract “political pressures” and referee disputes with New York officials in an investigation of the Indian Point nuclear power plant’s operations (15-02730).

The plant owner on Tuesday asked the New York Public Service Commission to appoint the judge to handle disputes over confidential documents and other matters related to an investigation of the plant ordered last month by Gov. Andrew Cuomo after two unplanned outages.

Indian Point Nuclear Power Plant (Source: Wikipedia)

Cuomo has called for closure of the plant for several years because of its proximity to New York City. He said the plant’s two units have had 13 unplanned shutdowns since June 2012, including two incidents nine days apart last month.

“We must ensure that the 20 million people that live within the shadow of Indian Point are truly safe from a nuclear incident … [so] I would specifically request that you examine the capital and maintenance budgets at the plants and their potential impact on these outages, and the impact these sudden outages can have on the continued safe operation of the plants,” Cuomo wrote in a letter to PSC Chairman Audrey Zibelman on Dec. 16.

Cuomo ordered the PSC to report the findings of its investigation by Feb. 15.

In two rounds of interrogatories in recent weeks, Entergy said, PSC staff sought information on finances and operations that go beyond a state’s jurisdiction and are the purview of federal regulators.

“Given the political and timing pressures being imposed on [Department of Public Service] staff, there is a particular need for an impartial ALJ to resolve Entergy’s objections,” the company wrote.

“The investigation is equally unprecedented in that it seeks highly detailed financial and operational information regarding Indian Point spanning across five- to 10-year time periods, even though Indian Point must earn its revenues from the wholesale markets pursuant to tariffs within the exclusive regulatory authority of the Federal Energy Regulatory Commission.”

Entergy said it will cooperate “in good faith” with many aspects of the investigation but finds the scope “objectionable.”

In December the Nuclear Regulatory Commission told Entergy it can continue to operate Indian Point’s Unit 3 under its existing 40-year license, which expired last month, while its license renewal review continues. Unit 2’s license expired in 2013, but it is also operating under an extension while the company’s application is under review.

The two outages that prompted Cuomo’s action occurred on Dec. 5 and 14.

In the first incident, a faulty electrical breaker controlling a roof fan caused a trip at Unit 2, according to NRC. The commission said operators manually shut down the reactor when the faulty breaker caused a drop in voltage to the mechanisms controlling about 10 of the reactor’s control rods.

On Dec. 14, Entergy said the shutdown was caused by a “disturbance” on the non-nuclear side of the plant that connects to the grid.

January 19, 2016

FERC Approves Sale of Doomed New York Coal Plants

By William Opalka

FERC on Wednesday approved the sale of two upstate New York power plants, the same day Gov. Andrew Cuomo vowed the generators would “transition” away from coal or be closed by 2020.

The commission approved the sale by Upstate New York Power Producers of the 312-MW Cayuga plant outside Ithaca and the 668-MW Somerset facility in Niagara County to Blackstone Group unit Riesling Power “as consistent with the public interest” (EC15-214).

With the Dec. 31 mothballing of NRG Energy’s Dunkirk plant and the 380-MW Huntley Power Station in Tonawanda expected to close at the end of March, Cayuga and Somerset will be the last two coal-fired plants in New York.

Their continued operation runs headlong into Cuomo’s clean energy agenda, which calls for the state to obtain 50% of its energy from renewable resources by 2030.

Cuomo repeated that pledge in his annual State of the State address Wednesday. “We will eliminate all use of coal in New York state by 2020. We will help the few remaining coal plants transition, but we must clean our air and protect our health and that must be our first priority,” Cuomo said.

According to the governor’s office, coal accounts for 4% of electricity generation in New York, a number sure to drop even more absent Dunkirk and Huntley.

A group of bondholders formed Upstate New York Power Producers to purchase Cayuga and Somerset from the bankrupt AES Energy East for $240 million in 2012. No price was disclosed when the sale to Riesling was announced in September. (See Blackstone Seeks Two Coal-fired Plants in New York.)

Cayuga is operating under a controversial reliability support services agreement that runs until June 30, 2017. It also has a proposal before the New York Public Service Commission to repower to natural gas with ratepayer assistance paid over the next 10 years. (See Cayuga Power Plant Repowering Opposed.)

The Sierra Club, which opposes the above-market payments, asked FERC to compel Riesling to provide information regarding the Cayuga plant’s future.

FERC ruled those questions outside the scope of the proceeding and said the sale “will not have an adverse effect on rates.”

No plans about the future of the Somerset plant have been made public. “There are a number of announced initiatives on the future of energy markets in the state of New York. The details on how they will be achieved while maintaining a reliable electric system in the state at a fair economic price will highlight the importance of these assets to the system,” Riesling spokesman Michael Enright said Monday. “We look forward to reviewing the details of the governor’s plan and will, upon approval of the sale by the PSC, seek to promptly engage in constructive dialogue with major stakeholders to create a path forward.”

That path, according to a briefing book released in conjunction with Cuomo’s budget, includes a directive to state regulators to work with NYISO to “develop a regulatory framework that will ensure system reliability while facilitating repowering to cleaner fuel or closure.”

In reaction to the budget and in anticipation of pending action before the New York Public Service Commission promoting clean energy development, an organization representing power generators again emphasized a market-based approach.

Gavin Donohue, CEO of the Independent Power Producers of New York, said “generators that are able to meet their emissions requirements and perform economically should be allowed to operate in the state.

“State strategies that pick winners and losers are especially redundant in light of record low fuel and wholesale market prices that are currently driving uneconomic facilities to retire,” he continued. “Just this past December, New York saw the lowest wholesale price of energy since the market was created, and those prices are being reflected in consumers’ energy bills and generators’ decisions to invest in new resources.”

January 19, 2016

MISO Seeks to Launch Ramp Product April 1

By Amanda Durish Cook

CARMEL, Ind. — MISO will ask FERC for an April 1 effective date on its new ramp capability software, RTO officials said Friday.

Dhiman Chatterjee, MISO’s senior manager of market analysis, said he expected the commission to approve the request, which will be filed Feb. 1. The commission approved the product in October 2014 (ER14-2156).

“They have understood the need for a product to explicitly address ramp concerns,” he said at a technical workshop Friday, which focused on how stakeholders should incorporate new ramp capability software into their systems and how the product fits into MISO’s market.

“We’ll do our best to do what we can [to answer questions] today, and if we can’t address it today, we’ll make a note. We do have some time before the go-live date,” Chatterjee said.

A ramp capability customer care line is scheduled to open Feb. 9. MISO plans to make the production interface on ramp capability offers available on March 25.

In Development Since 2011

The software, which has been in development since 2011, is designed to respond to short-term variations in load by holding back a portion of rampable capacity from the five-minute dispatch.

With “increasing renewable penetration and interchange flexibility, net load variations and uncertainties impose challenges to maintain real-time power balance,” MISO said.

MISO will set ramp requirements for the day-ahead and real-time markets based on load forecasts and historical analysis. The new products won’t eliminate all short-term scarcity events, such as sudden generator losses and large changes in interchange.

“Now we’ll have the capability to prepare for both the anticipated and unanticipated ramp needs,” MISO Market Design Engineer Congcong Wang said.

Jason Howard, manager of market quality, said while participation isn’t mandatory, it would be difficult for operators to completely ignore the ramp software’s benefits, as revenues earned from software use would contribute toward reducing any owed make-whole payment.

“We’re essentially saying in our FERC filings that this is like our [revenue sufficiency guarantee] make-whole payments,” he said. Up or down ramp capability will be included as additional revenue components under the revenue sufficiency guarantee.

Resources able to respond to five-minute energy dispatch instructions — generation, type II demand response and external asynchronous resources — will be able to offer ramp capability. Energy storage is not eligible and dispatchable intermittent resources will be able to provide down ramp based on their ability to reduce output in accordance with load following needs.

Opportunity Costs

Resources that are dispatched out of merit order through the clearing of up or down ramp capability will be compensated for lost opportunity costs at a maximum of $5/MWh.

MISO says the product could save $3.8 million to $5.4 million in dispatch and commitment costs.

Howard said use of the ramp product will result in two new line items on settlement statements, a day-ahead procurement charge and a real-time procurement charge. Payments for those providing ramp will be included under make-whole payments.

Chatterjee said MISO will likely conduct a study on the ramp product to gauge effectiveness over its first few years of operation.

Jason Fogarty said Potomac Economics, MISO’s Independent Market Monitor, is supportive of the product. He said he isn’t worried about a small number of resources not offering ramp, but he would become concerned if a large portion of resources decline to participate.

“If ramp capability withholding becomes prevalent, we would make a suggestion to MISO to update their software programs,” Fogarty said.

Going forward, Fogarty said, the Monitor will report quarterly on quantities of withheld up or down ramp capability, the impact of the $5 demand curve on procurement and any potential “market power or efficiency concerns.”

MISO Senior Customer Trainer Ron Matlock said additional training sessions for stakeholders will be held on Feb. 17, Feb. 24 and March 2.

January 19, 2016

FERC Accepts ISO-NE’s Solar Count over Protests

By William Opalka

FERC has accepted ISO-NE’s 390-MW reduction in its load forecast, reflecting the impact of distributed solar resources.

The commission rejected the New England Power Generators Association’s contention that the calculations for behind-the-meter generation hadn’t been sufficiently vetted (ER16-307).

“We find that ISO-NE has properly incorporated non-embedded solar resources into its [installed capacity requirement] calculation and has supported that action. We dismiss the arguments made by protesters to the contrary,” FERC wrote.

Solar is only a small piece of the 35,126 MW of ICR resources in the 10th Forward Capacity Auction set for next month, but the reduction was enough to displace the need for one small generating plant for the 2019/20 capacity commitment period.

The RTO said the only change in its assumptions from prior auctions was the inclusion of behind-the-meter solar resources that are not yet reflected in historical loads.

NEPGA said the calculation should be determined by a Section 205 proceeding before FERC. (See Generators Dispute ISO-NE on Solar Capacity.)

However, FERC ruled that the process by which stakeholder committees had considered calculations for the solar values had conformed to the RTO’s Tariff, even though ISO-NE, the New England Power Pool and various stakeholders had failed to reach consensus.

January 19, 2016

Latest Z2 Credit Project Delay Renews Old Frustrations

By Tom Kleckner

OKLAHOMA CITY — Member frustrations with SPP’s Z2 crediting project bubbled to the surface again last week when staff told the Markets and Operations Policy Committee of a new delay.

“It’s an open wound that continues to fester and opens again whenever we seem to make progress,” said The Wind Coalition’s Steve Gaw.

SPP staff told the MOPC last Tuesday the project’s complexity and the challenges in processing historical data have pushed the project’s expected completion to November, when the first Z2 credits are now expected to be invoiced.

Not Pleased

That did not please members, who had been expecting an initial indication of their liabilities or credits this month.

The Z2 crediting project dates back to the last decade as a result of years of incorrect credits for transmission upgrades. The task force working on the project estimated last year creditable upgrades of $750 million but said in October it hoped to present better estimates this month. (See “Z2 Crediting Task Force Remains on Track” in SPP Markets and Operations Policy Committee Briefs.)

Some members requested notice from SPP about the size of the impact.

“We don’t know if it’s a 5-gallon bucket, a semi-trailer or an oil tanker,” said Oklahoma Gas & Electric’s Greg McAuley. “I can’t give my executive team any insight at all. We would like some transparency so we know what the size of the bucket is. If it’s a $5 issue, we don’t care. If it’s $5 million, we do.”

“Every single entity in this room gets impacted, because the longer this festers, the more FERC gets interested,” Gaw said. “The delay does not keep the amount of money from accumulating.”

Upgrades Since 2008

The project team is developing software that will properly credit and bill transmission customers for system upgrades that date back to 2008, in accordance with Tariff attachment Z2. The problem has been avoiding over-compensating project sponsors and including a way to “claw back” revenues from members who owe SPP money for other reasons.

“The project goes so far back in time many databases have changed format,” said Steve Purdy, manager of transmission service studies. “We knew there would be some of that, but those issues are taking longer to deal with than we initially anticipated.”

Purdy said staff has “modularized” the system, so that some software is functional before others. Staff has completed two modules — accounting for 48 of 58 total system components — and is testing a third.

Purdy said 17% of the components have yet to be developed, but that the transmission owner and customer collection effort is mostly complete. He told the committee that additional testing will be required to cover the more complex processes, where some manual procedures are in place.

“We will process data, stop and make manual adjustments,” Purdy said. “The system run times are estimates. We haven’t exercised the system yet, so we’re basing the estimates on what we think it will look like.”

Staff now expects the historical data processing to begin in late March and run through late August. The first reports would be generated and reviewed in August and September, with invoicing beginning Nov. 4.

“NextEra certainly doesn’t feel any better about this, given the answer you just gave,” said Aundrea Williams, director of regulatory affairs and strategies for NextEra Energy Transmission. “[This project] is past red, perhaps maroon. Why are you more confident today that I can rest assured Nov. 4 is a real date? Is there any way we can get anything going before Nov. 4?”

Additional Staff Assigned

Purdy said additional staff has been assigned to the project and some work is being conducted in parallel “to see if we can speed this up.” Staff is also considering postponing some work past the Nov. 4 go-live date and conducting “outreach sprints” with affected parties to speed up the process.

Purdy noted the project estimates are on the “long side,” given the historical data processing piece in the middle is “the squishiest part of the schedule.”

ITC Holdings’ Marguerite Wagner reiterated members’ desire for an “order of magnitude” number. Charles Locke, SPP lead regulatory analyst, responded, saying, “It’s a very long and complicated calculation even to provide an order of magnitude. We may be able to provide data on the gross payment obligations before September, but that won’t give the broad spectrum of impacts across SPP.”

“It’s very hard for me to explain in our public world,” said Xcel Energy’s Bill Grant, referring to his company’s responsibilities to shareholders and regulators. “This may be a big financial decision we’re fixing to make, or not at all. I don’t want to go back and say I made the wrong decision because I didn’t have the right information.”

Staff promised improved communications around the project. Gaw said when he participated in a Regional Tariff Working Group meeting two weeks’ prior, the November date was never mentioned.

“We will program in a number of checkpoints once we start processing data. The checkpoints will allow us to make more frequent adjustments to the schedule so we know what we have,” Purdy said.

‘Back Burner’

“It’s easy to look back and say we knew it would be hard,” MOPC Chair Noman Williams, of South Central MCN, told the Strategic Planning Committee on Thursday. Williams said the Z2 project “got put on the back burner” as SPP introduced the Integrated Marketplace and added the Integrated System.

“Getting our hands around all that data and the numbers is not an impossible task, but it will take a lot of effort to get there,” he said.

Given the project’s current status, the MOPC delayed approving a payment plan until its April meeting. The task force is currently suggesting two options, a traditional payment plan and a staggered billing approach, either of which will require a FERC filing.

Under the payment plan, SPP would offer each entity the option of being billed the entire amount at once (thus avoiding additional interest) or in equal installments, as determined by stakeholders. Under the staggered approach, stakeholders would be billed based upon time increments; years one and two would be billed in the first quarter after go-live, years three and four in the second quarter, and so on.

SPP’s regulatory and legal departments are currently identifying any Tariff provisions required by implementing the credit billing process.

January 19, 2016

Next up in Ohio PPA Battle: Dynegy Weighs in

By Ted Caddell and Suzanne Herel

Dynegy entered the Ohio PPA fray last week, floating an offer to the Public Utilities Commission of Ohio that it said would save consumers in the state $5 billion over eight years.

The company said it was making its counter offer “in response to the exorbitant and counterproductive subsidies currently under consideration” for American Electric Power and FirstEnergy. It would either provide power from its existing generation fleet in the state, or replace subsidized American Electric Power and FirstEnergy plants with new, natural gas-fired generation.

The Ohio-based companies have proposed power purchase agreements to PUCO that would provide a guaranteed return for their embattled generating stations for eight years. PUCO staff has signed on to both proposals, which have been attacked by independent power producers and others. (See Merchant Generators Lead Opposition to FirstEnergy-Ohio Settlement.)

Dynegy’s offer comes two weeks after Exelon made its own offer to PUCO, proposing a competitive bidding process to supply the 3,000 MW for which FirstEnergy is seeking guaranteed rates (the combined value of FirstEnergy’s W.H. Sammis coal plant and its Davis-Besse nuclear station).

Local Provider?

One difference in Dynegy’s offer is that it bills itself as a local provider. “The power provided by Dynegy will be generated by Ohioans, at Ohio plants, for Ohioans,” Dynegy said in its announcement. Dynegy said it has 5,400 MW of generation in Ohio and hundreds of employees in the state and would use the state’s natural gas, “providing further benefits to the state.”

Dynegy CEO Robert Flexon, who has threatened to sue if PUCO accepts either the AEP or FirstEnergy proposals, said his company has the winning answer.

“If the PUCO and other elected officials in the state are interested in protecting consumers’ and businesses’ long-term interests while ensuring long-term reliability and price stability, then in lieu of accepting FirstEnergy’s and AEP’s proposals for long-term power purchase agreements, the PUCO should adopt one of the alternate, superior proposals Dynegy is putting forth,” he said. “The PUCO could also institute a request for proposal process containing the same arrangements in the AEP and FirstEnergy PPA proposals. Exelon’s recent proposal is also thoughtful, and Dynegy agrees with Exelon that this process should be competitive.”

Flexon will join CEOs from Calpine, NRG Energy and Talen Energy, as well as officials from Advanced Power and the PJM Power Providers Group (P3), in Columbus on Wednesday to lobby against the deals. The officials will hold a press conference at the state capitol at 2:15 p.m.

FirstEnergy: Dynegy ‘Misses the Point’

FirstEnergy spokesman Doug Colafella said Dynegy’s offer is off the mark.

“Dynegy’s proposal offers few specifics and provides no assurances that its power plants in the region will continue operating over the long term,” he said Friday. “Dynegy is a power marketer from Houston with an established track record of entering and exiting competitive markets. While its brand of investors may be willing to tolerate its ‘boom and bust’ approach to energy markets, this approach fails to deliver on two key policy goals in Ohio — energy stability and economic stability.”

“In addition,” he said, “Dynegy’s offer to fill the void with gas-fired plants if Sammis and Davis-Besse were forced to close completely misses the point about having a diverse set of fuels available to produce electricity in Ohio, an important ingredient for ensuring price stability for customers.”

AEP: Dynegy Wants Higher Prices

AEP Ohio spokeswoman Terri Flora also took a shot at Dynegy’s new generation option.

“If Dynegy could build new generation in Ohio under current market conditions, they would,” she wrote. “But, they haven’t built new generation in Ohio and they can’t afford to build it under current conditions. They need energy costs to rise dramatically for their business model to work so they want to force existing power plants to close.”

FirstEnergy Hearings Continue

The sparring proposals and letters came as PUCO continued hearings last week on the FirstEnergy proposal. The hearings are expected to run through the end of this week. Final arguments are likely in February and a commission vote possible by March, the Cleveland Plain Dealer reported.

On Thursday, lawyers for the Sierra Club questioned PUCO’s director of rates and regulatory affairs about FirstEnergy’s projection that natural gas prices will rise above $4/Mcf — a key assumption in the company’s contention that its proposal will save consumers money.

Prices for January are below $2.40/Mcf and New York Mercantile Exchange futures are below $4 through 2024.

FirstEnergy Answers PJM Member Criticism

FirstEnergy also responded to criticism of its proposal from P3 and the Electric Power Supply Association in a letter to the PJM board. (See Exelon Calls FirstEnergy PPA ‘Grossly Lopsided,’ Says it can Offer a Better Deal.)

Amid an industry in transition, “a number of states are considering retail rate policy reforms that support long-term resource planning, generator diversity and economic stability,” wrote Steven Strah, president of FirstEnergy Utilities. “While some participants may disagree with our proposal, it is legal from a state and federal perspective, and consistent with traditional state and federal regulatory rules.”

Strah also criticized PJM’s request that PUCO require FirstEnergy and AEP’s Ohio generators to offer their output into the RTO’s markets at no lower than their actual cost, with no consideration of offsetting revenue provided by Ohio retail customers. (See PJM Seeks Changes to AEP, FirstEnergy PPAs.)

Strah said such a mandate would violate federal appellate court rulings that prohibit state regulators from “dictat[ing] generator offer behavior in PJM’s FERC-jurisdictional wholesale markets.”

Meanwhile, the independent generators received support from Advanced Power Asset Management, which is developing two combined cycle projects in Ohio.

In its letter to the PJM board, it called the FirstEnergy and AEP deals “a special subsidy to incumbent Ohio- and Indiana-based PJM generators [that] will circumvent the PJM capacity and energy markets,” lowering prices for other market participants and creating a disincentive to new investment.

Advanced Power is developing Carroll County Energy, a 700-MW natural gas-fired combined cycle generator expected to go online in the second half of 2017. The $899 million project is fully funded, “predicated on the PJM market mechanism, which is the largest and most liquid competitive capacity and energy market in the U.S.”

Also being developed — but not yet funded — is the 1,100-MW South Field Energy combined cycle project in Wellsville, Ohio.