Page 1182 – RTO Insider

April 20, 2018

Settlement on Abandoned East Coast Tx Line Wins FERC OK

By Amanda Durish Cook

FERC has approved a settlement between PJM, Exelon and the Illinois Commerce Commission over abandonment costs for the canceled Mid-Atlantic Power Pathway (MAPP) transmission project.

Under the uncontested settlement accepted by FERC on Thursday, Exelon subsidiary Baltimore Gas and Electric’s pricing zone will bear more costs of the project while the Commonwealth Edison zone’s responsibility will not exceed $75,000 — less than half of the costs it was originally assigned. FERC said PJM must disburse refunds if the ComEd zone has already paid more than $75,000 (ER17-1016-001).

FERC CC TXU Corp. natural gas pipelines — | *Pepco Holdings Inc.*

Proposed more than a decade ago, the $1.05 billion, 500-kV MAPP project would have extended about 230 miles from northeastern Virginia through southern Maryland and Delaware, crossing beneath the Chesapeake Bay and Choptank River to southwestern New Jersey.

In 2009, PJM assigned BGE two baseline upgrades for the project, but the RTO’s Board of Managers canceled the project in 2012, saying it was no longer needed to maintain reliability. The line was originally included in PJM’s 2007 Regional Transmission Expansion Plan.

Early last year, PJM submitted Tariff revisions on BGE’s behalf so the utility could recover about $1.2 million in abandoned plant costs.

The ICC protested, arguing that ComEd should not have to bear the costs of a canceled line that never stood to benefit its Midwestern territory. ComEd’s zone stood to incur 13.43% of the cost of BGE’s upgrades under PJM’s postage stamp cost allocation methodology.

“Given that MAPP is a canceled project, the ComEd zone does not derive any benefits from the MAPP project. … The load in the ComEd zone did not contribute to the reliability factors that caused PJM to add the MAPP project to the RTEP in the first place. The beneficiaries and cost causers of the MAPP project are located on the East Coast and that is where the commission should allocate the costs,” the ICC wrote.

The ICC also pointed to rulings by the 7th U.S. Circuit Court of Appeals, which twice remanded FERC’s approval of PJM’s regionwide postage stamp cost allocation for new 500-kV+ transmission projects (See Despite Lengthy Negotiations, PJM Cost Allocation Settlement Still Finds Detractors.) The 7th Circuit said that PJM’s high-voltage lines are “all located in PJM’s eastern region, primarily benefit that region and should not be allowed to shift a grossly disproportionate share of their costs to western utilities on which the eastern projects will confer only future, speculative and limited benefits.”

April 20, 2018

FERC OKs MISO TMEP Cost Recovery Schedule

By Amanda Durish Cook

FERC on Tuesday approved MISO’s proposed cost recovery schedules for its new category of smaller interregional transmission projects with PJM. The commission did not order any changes (ER18-867).

The commission said the tariff schedules for MISO and its transmission owners for recovery of costs on targeted market efficiency projects (TMEPs) is effective April 18.

FERC said the schedules “help to ensure that the transmission owners that construct TMEPs, whether located in MISO or PJM, will have the opportunity to recover the costs of doing so.”

The approved schedules assign MISO’s share of the project costs to all transmission pricing zones that receive a congestion contribution benefit from the project of at least $5,000 or 1% of the total share per zone. Any zones that don’t meet the $5,000/1% threshold would have their costs reallocated to the remaining zones that do. FERC approved MISO’s TMEP cost allocation methodology in October.

TMEPs are small interregional transmission projects meant to address historical congestion along MISO and PJM’s seams.

The RTOs’ boards approved the first TMEP portfolio last year, consisting of five congestion-relieving upgrades in Illinois, Indiana, Michigan and Ohio. The projects, which have individual $20 million cost caps, will coincidentally cost $20 million combined. On average, the projects’ costs will be allocated 69% to PJM and 31% to MISO based on projected benefits, which are expected to reach $100 million.

TMEP cost allocation — | © *RTO Insider*

Regulators from MISO South challenged the recovery schedules, as they similarly challenged MISO’s regional cost allocation plan. The Arkansas, Louisiana, Mississippi and Texas public service commissions, and the New Orleans City Council, asked FERC to require MISO clarify that the TMEP schedules do not apply to South. They also wanted a commitment that MISO will create a new TMEP cost allocation methodology before the December expiration of the five-year transition period that limits cost-sharing in South.

FERC said the regulators’ requests were beyond the scope of the proceeding. The commission said last month in a separate docket that MISO has already committed to filing a new regional cost-sharing method for its share of TMEP costs after the transition period. (See Rehearing Denied on MISO South Cost Allocation.)

The Mississippi PSC had also argued for a four-year limit on TMEP cost recovery; FERC declined to order such a provision.

New TMEPs in 2019?

At an April 18 MISO Planning Advisory Committee meeting, Eric Thoms, manager of interregional planning and coordination, said MISO and PJM are evaluating the need for a new TMEP study this year.

Thoms said that MISO is leaning in favor of a study, as the RTOs have experienced about $500 million in congestion payments on more than 200 market-to-market flowgates from 2016 to 2017.

“All indications are at this point that it would be prudent to proceed with a TMEP study this year,” Thoms said.

By May, the RTOs will also make an announcement on whether they will begin a traditional two-year coordinated system plan study to identify more expensive seams projects. The RTOs have yet to approve a major seams transmission project under their interregional market efficiency project category.

April 19, 2018

MISO Rebuts NERC Findings on Gas Risks

By Amanda Durish Cook

MISO on Wednesday challenged a 2017 NERC assessment that found two areas in the RTO would “experience transmission challenges during an extreme event” involving a disruption of natural gas delivery.

Late last year, NERC released the results of an assessment that studied 24 “geographic clusters” that contain more than 2,000 MW of gas-fired generation and said 18 of them “demonstrated the need for additional follow-up and analysis, based on power flow and stability issues” of the “extreme cases” it ran. (See NERC: Natural Gas Dependence Alters Reliability Planning.)

“Most of the risks were on the East Coast or in the Southwest, but there were two in MISO,” Senior Policy Studies Engineer Jordan Bakke said, referring to an area on the Missouri-Illinois border and the Amite South load pocket in southeast Louisiana.

MISO told the April 18 Planning Advisory Committee meeting that those two areas have access to alternative fuel sources and are not at risk of N-1 contingencies.

“We think the method employed in this study was not the most optimal. … These risks that were found are not necessarily reasonable in MISO,” Bakke said. “MISO has assessed the two regions and found that they were not single-source … issues, and do not account for a generator’s ability to procure fuel from an alternate pipeline connection.”

Bakke said MISO, which has discussed the study results with NERC, will proceed with its own usual natural gas analyses, though it plans to add a feature to verify that dual-fuel units can access their second source of fuel. By November, MISO also plans to release results of an in-progress study on the impact that large gas pipeline contingencies may have on its system. (See “Sign-of-the-Times Studies,” MISO in 2018: Storage, Software, Settlements and Studies.)

MISO said it has been studying natural gas disruptions as part of its reliability planning since 2015 and currently uses 31 gas contingencies to evaluate “transmission needs and system risk.” MISO has repeatedly reported that only one planning scenario — the long-term loss of the largest natural gas pipeline for the entire summer peak season —would “slightly” elevate a regional loss-of-load risk.

Minnesota Public Utilities Commissioner Matt Schuerger asked if NERC’s assessment or MISO analyses had any merit when considering the natural gas generation outages during the extreme cold that hit the RTO in January. MISO staff said virtually all the gas generation outages involved generators with interruptible transportation, and little of the generation experiencing outages had back-up fuel plans.

April 19, 2018

UPDATED: NY Task Force Briefed on Carbon Charge Mechanics

By Michael Kuser

NYISO on Monday presented two options for pricing carbon emissions in the ISO’s wholesale market, saying the approach the ISO favors would not require changes to its commitment/dispatch software or the frequency of settlements.

“The cost of carbon will be known ahead of time, will be known to market participants,” said ISO staffer Nathaniel Gilbraith, who delivered the report to the Integrating Public Policy Task Force (IPPTF), which is jointly run by NYISO and the state’s Department of Public Service. The April 16 discussion was part of issue “Track 2” in the group’s five-track effort to price carbon emissions.

The ISO’s preferred approach would have suppliers embed the carbon charges into their all-in day-ahead and real-time energy offers, as they currently do with emissions costs under the Regional Greenhouse Gas Initiative.

Under the second approach, suppliers would submit emissions information for each segment of energy offers (start-up, no-load and incremental energy in dollars per megawatt-hour) with the ISO incorporating the information to calculate a carbon shadow price. It would require software changes. [Editor’s Note: An earlier version of this article incorrectly stated that neither approach would require software changes.]

Under both options, the ISO would dispatch units as it currently does to minimize production costs subject to system constraints. In either case, carbon charges might also need to be trued up, Gilbraith said.

The carbon price for generators subject to RGGI would be the social cost of carbon determined by the New York Public Service Commission minus the RGGI price. Generators not subject to RGGI, such as fossil fuel plants of less than 25 MW, would pay the full social cost.

The ISO could estimate emissions for the generators but would prefer to let suppliers self-report, said IPPTF co-chair Nicole Bouchez, NYISO principal economist. “We thought it made sense to have the companies who have the best information about their plants to do all that math instead of the ISO having to do, by necessity, approximations of it,” she said.

Another complexity is that emissions vary based on a plant’s heat rate, fuel type and where in the output range they are, she said.

“In order to really know the carbon output, you need to know the exact heat rate as well as the fuel that’s being used at that moment and what the carbon content of the fuel is,” Bouchez said. “Then there’s the question of start-up and no-load carbon emissions as well.”

Bouchez walked stakeholders through the ISO’s current bid and settlement process and how it might change under a carbon pricing regime.

Besides the current day-ahead and real-time market settlements, ““the carbon charge would introduce an additional generator settlement line item, which is based on the actual emissions that day times the applicable price in dollars per ton,” Bouchez said. “[This] gives the dollar carbon charges that would be charged to that generator, and that is based on the actual physical output of the plant.”

Loads would continue to pay the applicable locational-based marginal price (LBMP) for energy withdrawals. The process would also create a carbon charge “residual,” a dollar amount to be paid to load-serving entities to minimize the increase in retail electricity prices. The allocation of residuals will be discussed at a future task force meeting.

Price Transparency

Couch White attorney Michael Mager, who represents a coalition of large industrial, commercial and institutional energy customers known as “Multiple Intervenors,” asked what would be included in the market price. “Would the final market price be the LBMP plus carbon adder, minus the amount that’s passed back to load-serving entities? What would be transparent and public for every hour?”

Because many end-use customers have supplier contracts based on the market prices, “I think the customers are going to want to know that any money that’s passed back to LSEs at the wholesale level actually gets passed back to the consumers at the retail level, so I think they’re going to need transparency in terms of that price as well,” Mager said.

“The LBMP is still going to exist as the primary cost of a unit of energy,” Gilbraith said. “Similar to today, there are other associated charges, uplift or whatnot, that are allocated to loads. The joint staff team will be working through in June a proposal on how to allocate the carbon residuals back, and that’s a great issue to bring up in that venue, what data and what is made public through that process and at what level of granularity.”

Real-time Emissions

“These calculations are going to be done separately for day-ahead and real-time, and so all of this charging and reconciliation would be done separately for each market. Is that accurate?” asked Howard Fromer, director of market policy for PSEG Power New York.

“Day-ahead and real-time LMBPs will continue to exist as they do today, and so they will be developed based on day-ahead and real-time offers,” Gilbraith responded. “However, energy is only physically produced pursuant to a real-time schedule, so the only way a bill [for the carbon charge] will occur is … based upon a real-time schedule. … It’s based on actual, physical electricity production and the emissions associated with that production.”

The task force next meets on April 23 at NYISO headquarters.

April 19, 2018

FERC Finalizes Cyber Controls on Portable Devices

By Rich Heidorn Jr.

FERC on Thursday approved rules to prevent malware from infecting “low impact” computer systems through transient electronic devices such as laptops and thumb drives (RM17-11, Order 843).

The order approves a requirement outlined in the commission’s October Notice of Proposed Rulemaking directing NERC to modify reliability standard CIP-003-7 to mitigate the risk of malicious code that could result from third-party devices that frequently connect to and disconnect from low-impact systems. (See FERC Seeks Cyber Controls on Portable Devices; Sets GMD Plans.)

The commission reiterated the concerns it raised in the NOPR that the NERC standard “lacks a clear requirement to mitigate the risk of malicious code” that could result from third-party transient devices. “Accordingly, we direct NERC to develop a modification to the reliability standard to provide the needed clarity. Such modification will better ensure that registered entities clearly understand their mitigation obligations and, thus, improve individual entity mitigation plans,” the commission said.

However, the commission declined to adopt a proposal requiring NERC to “provide clear, objective criteria for electronic access controls” for low-impact systems. NERC tiers its cybersecurity requirements based on classifications of high-, medium- and low-impact Bulk Electric System (BES) cyber systems.

The commission said comments from NERC and others convinced it that the reliability standard already “provides a clear security objective that establishes compliance expectations.”

Instead, FERC ordered NERC to conduct a study within 18 months to assess the implementation of the standard to determine whether the electronic access controls adopted by responsible entities “provide adequate security.” The study was proposed in a joint filing by the American Public Power Association, Edison Electric Institute and National Rural Electric Cooperative Association, identified in the order as “trade associations.”

Reversal

NERC said that the standard requires responsible entities to “document the necessity of its inbound and outbound electronic access permissions and provide justification of the need for such access.”

The trade associations, Electric Consumers Resource Council (ELCON) and Transmission Access Policy Study Group said the proposal would be burdensome and ineffective. While it “appreciates the value establishing more tangible criteria for adequate low-impact BES cyber system controls … the additional requirements that the commission proposes would do nothing to harden a low-impact facility against the rapid evolution in cyber warfare,” ELCON said.

The trade associations urged a risk-based approach to allow responsible entities to focus their resources on assets that have a higher impact on reliability.

“Given NERC’s statements, we believe that there will be adequate measures to assess compliance with reliability standard CIP-003-7,” FERC concluded. “We expect responsible entities to be able to provide a technically sound explanation as to how their electronic access controls meet the security objective.”

Mitigation of Malicious Code

The trade associations and ELCON also opposed the NOPR’s proposal to require responsible entities to prevent malicious code from entering their systems via transient electronic devices used by contractors and other third parties. The trade groups said risk mitigation is implicitly required under Section 5 of the standard.

But FERC said the standard doesn’t go far enough. “While commenters agree that, at least implicitly, the mitigation of malicious code is an obligation, the lack of a clear requirement could lead to confusion in both the development of a compliance plan and in the implementation of a compliance plan,” the commission said. “In addition, although NERC contends that the proposed directive may not be necessary, NERC agrees that modifying reliability standard CIP-003-7 to address the mitigation of malicious code explicitly could clarify compliance obligations.”

FERC said the new standard also will improve reliability by requiring responsible entities to have a policy for declaring and responding to “exceptional circumstances” — defined by NERC as a natural disaster, civil unrest or a situation that threatens to impact BES reliability or presents a risk of injury or death.

April 18, 2018

FERC Whipsawed on Pipeline Policy in House Hearing

By Rich Heidorn Jr.

WASHINGTON — Congress will be watching FERC’s review of its policy on licensing natural gas pipelines very closely if the commission’s appearance before the House Energy Subcommittee on Tuesday is any indication.

FERC natural gas pipelines — Congress will be watching FERC’s review of its policy on licensing natural gas pipelines very closely. | © *RTO Insider*

Any changes FERC makes are unlikely to please all members, however.

At a hearing attended by all five FERC commissioners, both Republican and Democratic representatives complained that the commission has been too willing to approve pipeline projects and insensitive to landowners in their paths. Others, however, said the commission must speed up its approval process.

Energy and Commerce Committee Chairman Greg Walden (R-Ore.) said he hopes the commission’s review of its 1999 policy statem e nt on certifying new interstate pipelines, announced in December, will “result in more efficient and timely decisions.” (See FERC to Review Gas Pipeline Approv a l Process.) FERC Chairman Kevin McIntyre said the commission will outline its plans for the review at Thursday’s open meeting (PL18-1).

Walden cited reports that New England relied on two LNG shipments from Russia to get through the winter, fuming: “While cross-border trade with our neighbors in Canada and Mexico may be a win-win, we should never have to be reliant on the Russians for imports again.”

Speaking next, Rep. Frank Pallone (D-N.J.), the committee’s ranking member, said that he is concerned that ratepayers will be billed for unneeded projects and that landowners have no way to fight them. He called on the commission to conduct regional reviews of pipeline needs rather than evaluating each project individually.

Rep. Leonard Lance (R-N.J.), who is not a member of the subcommittee, attended the hearing nonetheless to tell the commission of his complaints over its approval in January of the PennEast pipeline project in Pennsylvania and New Jersey. The New Jersey attorney general went t o court last month to prevent the project developer from condemning more than 20 properties acquired under open-space and farmland preservation programs.

Lance also questioned whether FERC was conducting “robust economic analysis” in using contracts with pipeline affiliates as evidence of a project’s need.

“It’s my considered judgment that this [project] is not in the best interests of the United States and certainly not in the best interests of New Jersey,” Lance said.

Rep. Morgan Griffith (R-Va.) said “the frustration level in Virginia is so high” over FERC’s pipeline reviews that he has teamed up with Democratic Sen. Tim Kaine (D-Va.) on legislation he said would increase the transparency of FERC’s licensing process (H.R. 28 9 3, S. 1 3 14). “Tim Kaine and I don’t generally agree,” he noted.

Griffith complained that surveyors for a pipeline appeared unannounced in his district recently and said the commission had rejected his request for additional public hearings to make travel to the sessions less burdensome for his constituents. He suggested putting two or more pipelines into the same corridor to minimize impacts on landowners. “FERC can do a better job,” he said.

LNG Exports

Rep. Pete Olson (R-Texas) said some Gulf Coast LNG projects have fallen behind schedule because of delays in receiving FERC approvals. “I’ve heard rumors that FERC has only six to eight employees [responsible] for approving these … permits. I’ve heard you actually approached the [Department of Energy] for new [employees] to help out with the backlog of approving LNG permits,” he said. “Is that true?”

McIntyre did not answer the LNG staffing question but acknowledged the commission is planning to add staff to the Office of Energy Projects to process LNG and pipeline applications.

“It’s consuming an enormous amount of attention and manpower within the agency,” he said. “If there’s any suggestion that we are somehow not giving it our full effort right now, I can assure you that is not the case at all.”

The pipeline review was just one of the issues the committee addressed during the three-hour hearing, which Walden said was the first with the full commission since 2015. Also discussed were the commission’s grid resilience inquiry, the financial struggles of coal and nuclear generation, the Public Utility Regulatory Policies Act, cybersecurity, and last week’s technical conference on distributed energy resources. (See related story, Ready to Act on DERs, FERC Tells Congress.)

April 18, 2018

Report: Nuke Loss Would Undo Renewable Growth

By Rory D. Sweeney

The closure of four nuclear plants in Pennsylvania and Ohio would result in substantial increases in electricity bills and carbon dioxide emissions, among other air pollutants, while cutting jobs and economic productivity, according to a Brattle Group report released on Monday.

The report, commissioned by Nuclear Matters, a bipartisan pro-nuclear advocacy group, focuses on the Three Mile Island unit Exelon said last year it will close and the three plants FirstEnergy Solutions announced on March 28 it was closing: Davis-Besse and Perry in Ohio and Beaver Valley in Pennsylvania. (See FES Seeks Bankruptcy, DOE Emergency Order.)

The closures would trigger price increases of up to $2.43/MWh for Ohioans and $1.77/MWh for Pennsylvanians and eliminate the environmental benefit of all the zero-emissions generation installed in PJM over the past 25 years, according to the report. The four plants’ 4,745 MW generated 38.7 MWh of electricity in 2017, surpassing the 35 million MWh generated by wind, solar, and hydro resources in PJM, the report concluded. It would take 14 years for zero-emissions generation to recover to its 2017 level, Brattle said.

“This means that the retirement of these four nuclear generators would more than undo the entire emissions benefits of all renewable generation investments made to date throughout the PJM region,” the report concluded.

Matching the emissions-free output expected in PJM at the current pace would require another two years and doubling the current growth of generation from renewables to 4.8 million MWh annually. Attempting to replace the environmental benefits of the four nuclear plants with renewables could cost around $2 billion annually, based on the Energy Information Administration’s (EIA) national average renewable cost estimates and would not stop the lost capacity from the nuclear closures being replaced by fossil-fuel generation. “We estimate that about 72% of the replacement would come from gas-fired generation and 28% from coal,” the report said.

brattle group carbon emissions nuclear power nuclear plants — The graph shows that replacing the emissions-free generation of the four nuclear plants currently slated for closure in PJM would take 14 years. Matching the emissions-free output expected in PJM at the current trajectory would require doubling the current deployment rate of renewables and another two years. | *The Brattle Group*

“Following [nuclear plant] Vermont Yankee’s shuttering in New England, we saw devastating effects. The loss of tax revenues forced local officials to make major budget concessions to the detriment of their residents, including cutting their municipal budget by 20%, drastically reducing police services, and raising their property taxes by 20%,” said Judd Gregg, a Nuclear Matters Advocacy Council member and former Republican senator from New Hampshire. “In the year following the closure, carbon emissions increased by 2.5% due to nuclear energy being replaced by emission-producing sources.”

Annual CO₂ emissions would increase by more than 20 million metric tons if the plants closed and could create potential social costs of more than $900 million per year. It also would increase annual emissions of air pollutants such as sulfur dioxide, nitrous oxide, and criteria particulate pollutants by tens of thousands of tons, with potential social costs of $170 million per year.

Electricity bills would increase by $400 million for Ohio residents, $285 million for Pennsylvanians, and $1.5 billion across PJM annually, according to the report, due to increased clearing prices in the capacity and energy markets. At least 3,000 jobs would be “at risk” without including indirect jobs at the plants, and the closures would eliminate tens of millions of dollars in local tax revenues.

Other Voices

David Lochbaum, a nuclear safety engineer with the Union of Concerned Scientists, questioned the study’s economic conclusions, telling the Cleveland Plain Dealer that other plant closures have not led to economic disasters. “The unemployment in the other states is not rampant, despite the permanently shut down reactors. The price of electricity in the other states is not exorbitant, despite the permanently shut down reactors,” he said.

“So, why does Nuclear Matters believe the folks in Ohio and Pennsylvania cannot figure out what folks in other states have figured out?” Lochbaum asked.

Meanwhile, the American Petroleum Institute (API) sent President Trump a letter Friday, urging him to reject FirstEnergy’s request for an emergency order to save the nuclear plants. (See Perry Hints DOE Won’t Grant FES ‘Emergency’ Request.)

“The natural gas industry and the shale revolution are poster children for letting the markets work,” API President Jack Gerard said. “The energy abundance wrought by the shale gas revolution is a prime example of competition at work.”

Gerard said government intervention would jeopardize the “economic benefits delivered to consumers” by natural gas.

[EDITOR’s NOTE: Due to an editing error, an earlier version of this article mischaracterized API position on the FirstEnergy request.]

April 18, 2018

PJM: Won’t Abandon AI Project on Nuke Closure Threats

By Rory D. Sweeney

The Artificial Island (AI) transmission project could change or become unnecessary if the two nuclear plants it’s intended to support are shuttered, but retirement threats by plant owners aren’t sufficient to revise the project, the PJM Board of Managers said last week.

The board made the acknowledgement in response to concerns highlighted by the Delaware Energy Users Group in a March 12 letter. Michael K. Messer, the group’s president, urged the board to re-evaluate and potentially cancel the project following threats by owners of the plants, Exelon and Public Service Enterprise Group (PSEG), to close them. (See Del. Group Seeks to Block Artificial Island Project.)

“I can say with a degree of certainty that the retirement of one or more plants at the Artificial Island site would impact the scope of the transmission project,” PJM CEO Andy Ott, a board member, wrote. “However, at this time, absent announced retirements of either Salem or Hope Creek, the project assumptions remain intact.”

PJM Artificial Island Nuclear Plants — The Hope Creek and Salem nuclear units on Artificial Island in southern New Jersey | *BHI Energy*

Exelon and PSEG have announced that they will cancel future capital investments at the two Salem nuclear units they co-own and shut the plants down if New Jersey doesn’t provide them financial support. The state legislature on Thursday passed a bill that would provide the plants with subsidies costing ratepayers about $300 million per year. (See NJ Lawmakers Pass Nuke Subsidies, Boosted RPS.)

The AI transmission project was developed to address transmission stability problems at Salem and the neighboring Hope Creek unit in southern New Jersey and allow them to operate at full power without a book-size compilation of operating constraints. PJM’s first competitive solicitation under Order 1000, the Artificial Island project has been long mired in controversy. In June, the RTO announced several cost allocation alternatives that would shift much of the $280 million price tag from Delaware ratepayers to those in New Jersey and Pennsylvania. (See PJM: AI Costs Would Shift to NJ, PA Under New Allocations.)

Ott confirmed Messer’s concerns but said any changes to the project would be considered during the system reliability analysis if either plant submits a deactivation notice. “I agree that the analysis proposed by your letter is analysis that PJM should undertake to determine impact to reliability should a plant announce retirement and subsequently impact the Artificial Island project,” he wrote.

April 17, 2018November 13, 2023

ERCOT Board of Directors Briefs: April 10, 2018

ERCOT’s Board of Directors last week rejected an appeal by small public power distributors seeking a proposed change to the ISO’s Nodal Operating Guide regarding the definition of transmission owners.

The revision request (NOGRR149) exempts municipal distribution service providers without transmission or generation facilities from having to procure designated transmission owner (DTO) services from a third-party provider if their annual peak load is less than 25 MW. ERCOT’s Technical Advisory Committee in February unanimously rebuffed an appeal of an early subcommittee’s rejection of the NOGGR after it had been tabled for more than a year. (See “Members Reject Appeal from Small Municipalities,” ERCOT Technical Advisory Committee Briefs: Feb. 22, 2018.)

The proposal was developed in 2015 to settle the noncompliant status of six municipally owned utilities with loads of 9 to 21 MW as the Texas Public Utility Commission’s staff began to look into the issue. However, the NOGGR has never received a positive vote as it moved through the stakeholder process, being rejected three times and tabled nine times.

“Typically, by the time TAC considers a proposal, it has enough consensus to move the initiative forward,” said the Office of Public Utility Counsel’s Diana Coleman, advocating the TAC’s position during the April 10 board meeting. “All 30 TAC members were there, and it didn’t receive one positive vote.”

Pointing to the unanimous vote against the NOGRR at the TAC, board Chair Craven Crowell said, “This particular appeal doesn’t have any legs under it.”

ERCOT CEO Bill Magness told the board that accepting the appeal would be granting an “overly broad” exemption to as many as 53 eligible systems, which represent about 600 MW of the grid’s load.

“If we get into a load shed situation in the ERCOT system, we’re going to ask for the load shed that we need to solve a reliability problem,” Magness said. “It’s going to be distributed out to the participants in the markets to make it happen. We’re going to solve the reliability problem. … Being a part of the [ERCOT] system has its benefits and obligations, and one of those obligations is to participate in load shed.”

Tom Anson, legal counsel to the municipalities under the Small Public Power Group (SPPG), said his members have not been able to reach an agreement with transmission service providers to be their DTOs. He said the SPPG members faces “hundreds of thousands of dollars” to self-designate as DTOs.

“I know ERCOT is reluctant to grant exemptions, but it’s the cleanest thing to do,” Anson said. “It would conform the ERCOT rules to the reality that these small systems just don’t have enough load or other resources to justify the expenditure of the kinds of money to build the substations or other parts of interconnections — all of which, if done, would not increase ERCOT reliability. They would be spending lots of money, but getting no reliability benefits.”

Anson said he was offering a clean solution to the problem, because SPPG members and the larger transmission providers wouldn’t have to continue looking for market solutions.

“Despite lots of hard work, and some progress, we still don’t have permanent solutions in place for all of them. That’s because there is no instant infrastructure, and ERCOT doesn’t control action of third parties. It’s a clean solution because if we want to pursue other rule revisions, time and effort would be avoided.”

The board denied the appeal by a 12-1 vote, with two members abstaining. Carolyn Shellman, who represents the municipal market segment and serves as CPS Energy’s general counsel, was the lone member to vote in favor of the appeal.

Noting the importance of compliance with operating guides and the rule of law, Shellman struggled to balance that with carving out exemptions for “very small groups of entities … that are doing everything necessary to comply if they can.”

“The small power group has some unusual circumstances that may warrant looking at them differently,” she said. “I’m not in favor of a 25-MW exemption … but we do have a solution that works in the market and recognizes the importance of rules. I hate to reject the appeal and send it to the commission that is obligated to enforce the rules we have. I’d hate for them to be in a position to impose penalties that could be devastating on very small systems.”

The SPPG has 35 days to appeal the board’s action, or it can start an appeal process within the TAC by providing different alternatives or language to resolve the issue.

“These small systems are caught between a rock and a hard place,” Anson said. “We’re open to all creative ideas, and we welcome anyone’s thoughts.”

“TAC is willing and looks forward to working with the SPPG,” Coleman said. “It has indicated some of its alternatives would require additional revision requests. We look forward to getting those resolved.”

Tight Summer Conditions Subject of Conversation

Magness said the ISO sees “tight conditions” this summer, not surprising given the surge of coal-fired plant retirements last year that halved ERCOT’s planning reserve margin to 9.3%, 4 percentage points below its 13.75% target. (See ERCOT: Tight Summer Margins No Cause for Alarm.)

“We see sufficient generation [this summer], based on normal conditions,” Magness said. “We could be tested in abnormal situations, based on the tightness of the system.”

Staff have said they have numerous tools at their disposal to help meet what is expected to be a record summer demand of almost 73 GW, including ancillary services, demand response and generators capable of switching between neighboring grids. ERCOT is also working to remove reliability unit commitment (RUC) capacity from its operating reserve demand curve (ORDC), a move that is expected to result in more accurate scarcity pricing (see below).

Texas PUC Chair DeAnn Walker thanked Magness and staff for moving quickly to revise the ORDC, but she added a word of caution.

“I want to raise awareness that when we have changes like this, sometimes we see changes in market behavior,” she said. “I’m relying on ERCOT, and in particular Beth [Garza, the ERCOT Independent Market Monitor’s director], to be keeping their eyes on market behavior like this, to be sure it stays in line with our expectations.”

Garza, for her part, declined to project what will happen this summer. “We would like to share comparisons and contrasts for the last few years, and let you make your own determinations,” she said during her regular update to the board.

She highlighted recent developments in DC tie activity between ERCOT and its neighbors SPP and Mexico. She noted exports across the ties to Mexico have grown in recent years, while imports from SPP have fallen. The five ties have 1.2 GW of capacity but contribute only 389 MW to ERCOT’s capacity in nonemergency situations.

“That could be good news for the summer,” Garza said.

She said lower prices — and the narrowing price spread between ERCOT and SPP — have contributed to decreased imports to the Texas grid.

ERCOT has received more good news in recent weeks, with three previously mothballed generators notifying that they are returning to operational status:

Talen Energy’s gas-fired Barney Davis 1, effective May 7. Talen had said last year it would retire the unit, which has a summer seasonal rating of 300 MW.
The City of Garland’s Gibbons Creek facility, effective May 17. The 454-MW coal-fired unit was approved for seasonal status last year by the ISO.
Garland’s Spencer Units 4 and 5, effective June 1. The two gas units have a total of 118 MW of capacity.

The plants will add almost 900 MW to the ISO’s summer capacity.

ERCOT Projecting $7.2M Favorable Variance in Net Revenues

Magness told the board that ERCOT is projecting a $7.2 million favorable variance in year-end net revenues, driven by winter weather that pushed up load. Net revenues are $4.3 million over budget through February, thanks to the higher administration fees and a $2.1 million favorable variance in expenditures due to timing differences.

ERCOT also saw above-normal revenue neutrality (RENA) uplift charges and market uplift charges in January, Magness said, stressing that the market is functioning as designed.

RENA charges were $16.57 million, up from $7.18 million in December and $10.46 million in January 2017. Magness said congestion in the real-time market was the main driver, with high prices at one end of the constraint and limits on low prices at the other end pushing up RENA.

Market-based uplift to load in January saw charges totaling $71.78 million, compared to a $9.19 million charge in December and a $33.71 million charge in January 2017. High ancillary service costs for non-spin on Jan. 17 contributed to the increase.

Magness also noted two projects continue to track poorly and will be re-planned within months.

The congestion revenue rights system upgrade has been hampered by significant vendor defects. Magness said the vendor has committed to improving its deliverables, and a new go-live date will be set once the defects are resolved.

Integrating the IT change and configuration management system with the content management system will require more time than originally planned, and the scope was expanded to ensure controls maintain data accuracy. A re-plan is expected to be completed in May.

Consent Agenda Removes RUC Capacity from ORDC

The board unanimously passed its consent agenda, which included an other binding document revision request (OBDRR) that removes RUC capacity from the grid operator’s ORDC.

The change meets the PUC’s directive to remove RUC capacity from the ORDC as part of its project assessing the Texas market’s price formation rules (No. 47199). (See “Commission Directs ERCOT to Revise ORDC,” Marquez to Depart Texas PUC.) Magness said the OBDRR is expected to be implanted by June.

The ORDC creates a real-time price adder to reflect the value of available reserves and is meant to incentivize resources to produce more energy and reserves. PUC staff recommended removing both RUC and reliability-must-run capacity from the ORDC, saying it would ensure that scarcity pricing is accurate and reflective of market dynamics.

ERCOT staff said it would take two or three months and $30,000 to $40,000 to make the software changes, an increase from the $15,000 to $25,000 initial estimate. The affected systems include Market Management Systems, data and information products, and analytic data.

The consent agenda included six nodal protocol revision requests (NPRRs), a change to the retail market guide (RMGRR), two changes to the Resource Registration Glossary (RRGRRs) and two system change requests (SCRs):

- NPRR854: Allows non-opt-in entity (NOIE) transmission and distribution service providers to submit meter data for NOIE points of delivery, rather than incurring the expense of installing, testing and maintaining an ERCOT-polled settlement meter, resulting in decreased expenses for both the NOIE and ERCOT.
- NPRR858: Requires ERCOT to publish all current operating plan (COP) data submitted by generators after confidentiality has expired, a change from the limited subset currently available. The change provides transparency into all intra-hour updates to COP data, as generators can update them at any time and change aggregate information available to the market.
- NPRR860: Clarifies certain day-ahead market practices and cleans up protocol language to better match the current implementation, including clarifying 1) the language for offering in three-part supply and ancillary service offers for offline non-spinning reserve in the same hour for day-ahead consideration; 2) the self-commitment treatment of resources with only an ancillary service offer submitted for the day-ahead; and 3) ancillary service offer resubmission rules. Also removes the reference to CRRs being co-optimized in the day-ahead.
- NPRR864: Modifies the RUC engine to scale down commitment costs of fast-start resources with less than one-hour starts. Following the change, the RUC engine will recommend slow-start resource commitments only if re-dispatching online resources and market-based self-commitments of fast-start resources will not resolve the reliability issue. With the change in the generation portfolio, market-based commitment decisions could be made much closer to real-time than in the past, allowing more self-commitments to materialize in real time than is reflected in COPs many hours earlier.
- NPRR865: Requires ERCOT to publish shift factors for hubs, load zones and DC ties for the real-time market, mimicking the day-ahead market’s current practice and providing more information on the inputs used to calculate pricing aggregations.
- NPRR868: Modifies the hub bus and load zone definitions and price calculations to account for the current usage of power flow buses — as opposed to electrical buses — in the day-ahead market and congestion revenue rights auction systems. The rewritten formulas will clarify the scenario when buses are de-energized in contingency analyses and align the protocols with ERCOT systems. (A power flow bus — a collection of points on the system that are electrically connected and have zero impedance between them — is identified dynamically based on the status of transmission equipment. Electrical buses — physical transmission elements that use breakers and switches to connect loads, lines, transformers, generators and related infrastructure — are defined statically.)
- RMGRR0150: Clarifies the content and format of the competitive retailer safety net spreadsheet within the market guide and removes Section 9, Appendix A1: Competitive Retailer Safety Net Request, which eliminates conflicts between the appendix and language found in Sections 7.4 (Safety Nets) and 7.10 (Emergency Operating Procedures for Extended Unplanned System Outages).
- RRGRR015: Clarifies glossary definitions and detailed descriptions of data fields to help market participants successfully submit their resource asset registration forms (RARFs). The change does not add or delete any data requirements, does not require a revision of the existing RARF form and does not require resubmission of previously submitted data already accepted by ERCOT.
- RRGRR016: Provides amplifying direction to RARF users for completion of certain solar data and narrows the data in order to provide solar forecasters with more precise data.
- SCR793: Gives transmission service providers access to the same ERCOT-generated status telemetry as the ISO’s operators in monitoring line outages with calculated subsynchronous resonance condition monitoring points.
- SCR795: Updates the resource limit calculator’s formula for calculating dispatched generation by including the addition of a predicted five-minute wind ramp (PWRR). The PWRR will be calculated from the intra-hour wind forecast and a configurable factor to capture the forecasted five-minute wind ramp, relieving regulation service’s burden to cover the five-minute gain or loss of generation from variations in wind, and instead dispatch this energy economically.

— Tom Kleckner

April 17, 2018

Texas Regulators Seek More Details on SPS Wind Project

By Tom Kleckner

Texas regulators last week pressed Southwestern Public Service for more details to justify its plan to build 1.23 GW of wind generation even though it doesn’t need the capacity.

The company and parties to a settlement over the project agreed to file additional written comments to its application for construction (Docket No. 46936).

The Texas Public Utility Commission’s staff has issued a conditional approval of the wind farms’ construction, but the commissioners expressed reservations.

“Where I am now, you’re not going to like the answer,” PUC Chair DeAnn Walker told the parties to the agreement during an April 13 open meeting. “The more information you can provide me, the more likely it is you can satisfy the concerns I have.”

SPS wind generation — D’Andrea questions SPS representatives as Walker listens. | *TexasAdmin*

Walker raised a number of issues with the parties, the central one being “upon what legal basis” the PUC can grant an application for new generation “when the applicant admits that there is currently sufficient generating capacity on its system to serve its customers?”

SPS announced last year that it intended to build a pair of wind farms in Texas and New Mexico and secure a long-term contract for energy from another facility as part of parent Xcel Energy’s multistate investment in wind. Xcel said the projects are expected to save the region’s customers about $2.8 billion over a 30-year period.

The company said in March it had reached an agreement with commission staff, the International Brotherhood of Electrical Workers and Lea County Electric Cooperative. SPS said nine other parties in the docket do not oppose the company’s request. The State Office of Administrative Hearings has admitted the settlement testimony into the record and remanded the case back to the PUC without holding a hearing.

Commissioner Arthur D’Andrea echoed Walker’s comments, saying he had “strong discomfort” with the deal.

“The fact it’s a settlement makes it more difficult to see what’s going on,” D’Andrea said. “My understanding is that the usual role of the commission is to approve something that looks like a taxing authority. The utility, in return, builds generation. This looks like billions of dollars in taxing authority and in return, the citizens get a wind deal and production tax credits.”

SPS President David Hudson responded that the generation would save ratepayers money through avoided fuel costs from other generation and the production tax credits (PTCs). He said the project qualified for 100% of the PTCs by purchasing wind turbines in 2016.

“PTCs at 100% value are pretty substantial,” Hudson said, noting the rate would be more than 3 cents/kWh after revenue requirement tax calculations. “That’s it automatic flow back to customers as a benefit, plus the avoided fuel costs. So, it’s true, [customers] will be paying the capital cost for the investment and recovery in base rates, but they’ll be getting substantial benefits through … zero-fuel energy and credit for the [PTCs].”

“I appreciate you are being creative,” D’Andrea said. “I’m not trying to say, ‘Spend a half billion on coal plants and improve the scrubbers.’ I wouldn’t want to throw bad money after bad money. I’m a little worried this goes too far. You basically say you don’t need this generation and that this is purely a financial play. That seems to be a strange thing for us to be approving.”

Attorney Rex VanMiddlesworth, representing Texas Industrial Energy Consumers, agreed with D’Andrea that SPS’ application is “unusual” but said that if there’s an “honest broker” in the proceeding, it’s his consumers group.

“Our jaundiced view of the utility is they make money, whether a plant is economical or not,” VanMiddlesworth said. “We want to look at whether this is good for the ratepayers. There’s a lot of risk. What if it goes over budget or doesn’t perform well? We ultimately concluded that this plant was very likely going to save Texas ratepayers hundreds of millions of dollars over its life.”

D’Andrea said he could support the project based on its economics, but that he needed more than a handful of spreadsheets before rendering a decision.

The parties promised to supply the commissioners with additional information in a week. The PUC next meets in open session April 27.

SPS has proposed building a 478-MW wind farm in West Texas and a 522-MW facility in New Mexico, though only the Texas project is part of the proceeding. The company also plans a 30-year power purchase agreement for an additional 230 MW of wind generation from Bonita Wind Energy, a NextEra Energy Resources subsidiary.

PUC Approves Transfer of Bankrupt ExGen’s Assets

The commission also approved the transfer of nearly 3.5 GW of gas-fired power plants from bankrupt merchant generator ExGen Texas Power to its creditors: Fidelity Management & Research, Fortress Credit Advisors, GSO/Blackstone Debt Funds Management, Guggenheim Partners Investment Management, Oppenheimer Funds, PineBridge Investments and Avenue Capital Management.

Walker and D’Andrea agreed with staff’s recommendation to approve the transfer, which staff noted would give ExGen and the creditors and affiliates a combined 7.6 GW of capacity, 8.2% of the generation capacity in ERCOT or capable of delivery into the grid (Docket No. 47836).

“As the total combined capacity is below the 20% threshold, necessarily, the capacity owned and controlled by each applicant individually is also below the 20% threshold,” staff wrote.

ExGen, an Exelon subsidiary, filed for Chapter 11 bankruptcy in November, blaming low wholesale prices due to cheap gas and increasing wind production.

The five plants are: Wolf Hollow I, Colorado Bend I, Mountain Creek, LaPort and Handley.

Non-IOUs to be Added to Rate Review Schedule

The commissioners adopted a new rate review schedule for investor-owned utilities and asked staff to include non-IOUs in the same rule (Docket No. 47545).

The rule revision implements the provisions of Texas SB 735.

Staff’s proposal sets a schedule for 10 IOUs, beginning with Texas-New Mexico Power in August and ending with Oncor in October 2021.