MISO Seeks Stakeholder Input on Out-of-Cycle Process amid Entergy Controversy

By Chris O’Malley

CARMEL, Ind. — Stinging from objections to Entergy’s proposed Lake Charles transmission upgrade, MISO has launched discussions that could lead to refinements in its procedures for handling out-of-cycle requests.

The procedural review was initiated after transmission developers and independent power producers objected to staff recommendations that the MISO Board of Directors approve Entergy’s six out-of-cycle requests. The largest and most controversial request is a $187 million transmission upgrade that it says is needed to support new industrial development around Lake Charles, La. (See MISO Staff Hold Firm on Entergy Out-of-Cycle Request.)

The MISO board could vote on the requests Thursday.

“We really want you guys to dig in and really tell us how you believe things should be,” Matthew Tackett, a MISO principal advisor, told the Planning Advisory Committee on Wednesday.

Stakeholders have challenged Entergy’s load projections and questioned its assertion that the projects were needed to meet base reliability needs. They’ve also alleged that MISO failed to follow its Business Practices Manual and that it provided only limited opportunity for stakeholder review.

Entergy said the need to serve additional industrial load wasn’t realized until after the conclusion of the annual MISO Transmission Expansion Plan (MTEP) process. MISO officials said Entergy’s out-of-cycle request was consistent with publicly announced industrial plant expansions and economic growth data for Lake Charles. MISO said Entergy has not shared some specifics about the projected new load growth, citing customer confidentiality.

Ambiguities?

One issue rising out of the Entergy request is tariff language that states that an out-of-cycle project review must be driven by “urgent” needs that require an expedited review.

MISO’s Business Practices Manual states that such out-of-cycle projects have a need date within three years and an expected in-service date within four years of an OOC project submission. George Dawe of Duke-American Transmission Co., who represents the Transmission Developers sector, sought a rationale for the difference between need date and in-service date.

“I agree that the language as written could use some improvement,” Tackett said.

The term “urgent” could “be a little bit ambiguous,” said Tia Elliott, director of regulatory affairs at NRG Energy.

Tackett said the review ultimately comes down to striking a balance between adequate stakeholder vetting and successfully addressing the need “in a timely manner.”

Dawe has complained that MISO’s review of Entergy’s request seemed rushed and predestined for approval.

Tackett stressed that the out-of-cycle approval process is designed for special circumstances, not for long-term projects that ordinarily would be reviewed within MTEP.

He also said MISO has limited authority to override or invalidate a distribution company’s load forecasts. He noted, however, that load modifications often have to be reviewed by state utility regulators.

Steve Leovy, a transmission engineer at WPPI Energy, suggested MISO could perform studies during the MTEP process that anticipate and model future expansions so that it could be better prepared for significant demand-forecast changes.

Tackett invited stakeholders to offer comments and to provide redlined versions of the Business Practices Manual by May 15.

A summary of comments and suggestions will be presented at the June Planning Advisory Committee meeting.

April 21, 2015June 15, 2023

FERC Briefs

The Federal Energy Regulatory Commission on Thursday issued new reliability standards, denied rehearing on business practices and communication protocols and ordered a new format for electronic filing of required reports. The commission also outlined a plan for measuring the effectiveness of its initiatives to spur transmission spending.

Transmission Investment Metrics

FERC said it will begin collecting data on six transmission metrics in an effort to measure the effectiveness of Order 1000 and other transmission initiatives (AD15-12).

The metrics are intended to measure levels of transmission infrastructure by region and permit analysis of the impact of commission transmission policies.

They include two measures of persistent congestion, which FERC said would provide an indication of whether regions have invested enough in transmission to ensure reliability and reduce costs:

Annual number of Transmission Loading Relief (TLR) or unscheduled flow events, normalized based on retail load. This metric would apply in bilateral markets.
Persistence, in years, of price differentials between RTO/ISO market nodes and market-to-market flowgates. LMPs, forward capacity prices and trading hub prices will be used.

To gauge the impact of policy changes, three other metrics will measure relative transmission investment and the cost-effectiveness of that spending:

Circuit-miles of transmission added to the grid, normalized by retail load. Population density and other factors may need to be considered in using the metric to compare regions.
Load-weighted transmission investment, defined as the amount spent on new capital additions in a given year, weighted by retail load. Population density must be considered in comparisons.
Circuit-miles per dollar of investment, defined as the number of circuit-miles added in a year, divided by the total invested — a measure of cost effectiveness.

The final metric will attempt to measure the impact of Order 1000, which sought to open transmission development to competition. It would divide the number of bids or proposals from non-incumbents in a region by the total number of bids and proposals annually.

“This is important work that you’re doing,” Chairman Norman Bay told Ben Foster, an Office of Energy Policy and Innovation staff member who presented the metrics study to the commission. “The metrics presented by staff today will allow the commission and its staff to better see what works and what needs further improvement.”

FERC staff will consider whether to add more metrics as it gains experience with the initial six.

“This is an initial feasibility study,” Foster said in response to a question from Commissioner Philip Moeller on a timeline for further developments. “We’ve done an initial pass, but we want to look more deeply into it to see if in fact it will yield meaningful insights. So we don’t have a particular timeline for releasing any kind of analysis at this point.”

FERC spokeswoman Mary O’Driscoll said the effort will not impose any additional reporting requirements on RTOs or others, at least not immediately.

“This is the very beginning of the process,” she said. “If [FERC staff] need additional data they will seek it out at the time. For now, it’s all public data.”

Commissioner Cheryl LaFleur asked Foster if there was anything RTOs could do to help FERC get meaningful data.

Foster replied that staff is attempting to rely on publicly available data. “But we may well have questions, and if the people who compile that data would be open to helping to walk us through [it] … that would be the most helpful to us at this point,” he said.

Electronic Filing Protocols for Commission Forms

Electric utilities and others will be required to file FERC reports in XML (Extensible MarkUp Language), a replacement for the current software, Visual FoxPro, which is no longer supported by its developer, Microsoft.

Affected are four forms used by electric utilities:

Form 1: Annual Report of Major Electric Utilities, Licensees, and Others;
Form 1F: Annual Report of Nonmajor Public Utilities and Licensees;
Form 3Q: Quarterly Financial Report of Electric Utilities, Licensees, and Natural Gas Companies; and
Form 714: Annual Electric Balancing Authority Area and Planning Area Report.

Forms for natural gas companies and oil pipelines also are affected by the change (AD15-11).

Standards for Business Practices and Communication Protocols for Public Utilities

FERC denied a request by the Edison Electric Institute for rehearing of Order 676-H, which specified business practices and communication protocols for electric utilities. The order addressed redirect policies and included a requirement that transmission providers post on their Open Access Same-time Information Site (OASIS) explanations on their calculation of available transmission capacity (ATC) within one day (RM05-5-024). Compliance is required effective May 15.

Reliability Standards

The commission gave final approval to the following reliability standards developed by the North American Electric Reliability Corp.:

COM-001-2 (Communications) and COM-002-4 (Operating Personnel Communications Protocols). The rules require adoption of predefined communication protocols, including use of three-part communications, and an annual assessment of them. The commission ordered NERC to modify COM-001-2 to address internal communications that could have an impact on reliability (RM14-13).
BAL-001-2 (Real Power Balancing Control Performance) and four new definitions. The standard is intended to ensure that the grid maintains consistent system frequency. It adds a frequency component to the measurement of a Balancing Authority’s area control error (ACE). The commission ordered NERC to submit an informational filing on the potential impact of the standard and to revise one definition (RM14-10).

The commission also gave preliminary approval to, and invited comment on, two Notices of Proposed Rulemaking:

PRC-005-4 (Protection System, Automatic Reclosing and Sudden Pressure Relaying Maintenance), which requires testing and maintenance of certain sudden pressure relays. The commission said it plans a new definition and four revised definitions in the proposed standard (RM15-9).
PRC-002-2 (Disturbance Monitoring and Reporting Requirements), designed to ensure the availability of adequate data to allow analysis of bulk electric system disturbances (RM15-4).

Tech Conference on Reliability of Bulk Power System

FERC will hold its annual technical conference on the reliability of the bulk-power system on June 4 (AD15-7). The conference, which will be held at FERC headquarters, will be webcast. FERC said a detailed agenda will be issued later.

— Rich Heidorn Jr.

April 21, 2015June 15, 2023

Smooth Transition as Bay Replaces LaFleur as FERC Chair

By Michael Brooks

WASHINGTON — The Federal Energy Regulatory Commission completed a bloodless transition Thursday as newcomer Norman Bay replaced five-year veteran Cheryl LaFleur as chairman in a meeting marked by the usual cordiality — and disruptive protesters.

ferc — Chairman Norman Bay, speaking at FERC’s open meeting on Thursday. © RTO Insider

Bay, who was appointed commissioner last August, officially assumed the chair on Wednesday from LaFleur, who had served as head of the panel since the November 2013 resignation of Jon Wellinghoff.

At the beginning of Thursday’s meeting, Bay presented LaFleur with two gifts: a framed letter from the New England Patriots thanking her for her service as chairman and a FERC jersey, which Bay said he hoped she would wear at every open meeting. A diehard Boston sports fan, LaFleur often wears her teams’ jerseys when they are in the playoffs.

After some affable remarks on LaFleur’s tenure from Commissioner Philip Moeller, LaFleur said, “I plan to be around for a while, so we don’t need to have any more tributes.” LaFleur, who joined the commission in July 2010, has said she plans on finishing her term, which expires in June 2019.

‘Excited’ to Work with Each Other

The congeniality between the former and current chairman betrayed no resentment over the way in which Bay took over the gavel.

While LaFleur publicly lobbied for the position after Wellinghoff’s resignation, President Obama nominated Bay last year. The choice was widely seen as engineered by then-Senate Majority Leader Harry Reid (D-Nev.), who publicly, and bluntly, said he did not want LaFleur as chairman.

Bay’s nomination received criticism from Congressional Republicans, who questioned his qualifications to be chair, as he had never served as a regulatory commissioner. Critics were also troubled that Bay would be leapfrogging the only female commissioner at the time. (See Analysis: LaFleur Cruises, Bay Bruises in Confirmation Hearing.)

The White House and Congress eventually struck a deal in which LaFleur would officially become chairman for nine months before Bay took the gavel.

Since then, LaFleur and Bay have been nothing but cordial in public.

“Congratulations to Norman Bay, who becomes Chairman April 15,” LaFleur tweeted last week. “Excited to continue working with him and all my FERC colleagues!”

“I thank former Chairman Cheryl LaFleur for her leadership at FERC and look forward to working with my colleagues on the commission and staff, as we build on the progress of the past to address the challenges of the future,” Bay said in a statement.

No Change in Routine

Besides the commissioners’ change in seating positions, FERC’s open meeting played out the same way it has for years: staff read their presentations, the commissioners thanked them and asked a few questions, and there was no debate on any issues.

During his first nine months as a commissioner, Bay made few comments and often merely thanked staff for their hard work. He was much more talkative Thursday, making several comments, albeit prewritten ones, on the import of the issues being discussed at the meetings. (See FERC Briefs.)

As has been the case over the past several months, the meeting was repeatedly interrupted by protesters opposed to the commission’s approval of natural gas infrastructure projects. After the first protester was escorted out by security, Bay quipped, “Well I guess one wouldn’t be a chairman without disruptions.”

Protesters were markedly more hostile this time around, yelling angrily at the commission as they were dragged — or sometimes carried — out by security. Each protester ended his or her tirade with a “Stop construction at Cove Point” chant.

Bay did not miss a beat while presenting his gifts to LaFleur. But after the fourth interruption, Bay made what seemed to be an impromptu statement:

“I just want to stay one thing. For the protesters out there, we respect your First Amendment rights, but just like Congress, the courts and every other federal agency, we have rules relating to the decorum of our proceedings. FERC believes in process. We welcome your views, we want to hear your views. But there are ways that you can do that. And you can do that by simply making submissions in our docketed proceedings. But interrupting these open meetings does not help your cause. It’s not even helpful in trying to get information to us, because they actually technically represent ex parte contacts. … If there are more of you in this room today who want to do some sort of disruption, please don’t.”

That plea went unheeded.

“Oh my God, we have a situation here!” cried out one protester in a mocking tone, quoting LaFleur in her comments to the National Press Club in January on the demonstrations. “The situation’s not going away! … There is no democracy here! You just ignore anything I write in the computer!”

While there were audible sighs of exasperation in the room after this final interruption, Bay remained unfazed.

Bay as Consensus-Builder?

As head of the Office of Enforcement, Bay received criticism from some members of the energy bar and former regulators for what they called his heavy-handed approach. (See PJM Trader Calls FERC on Manipulation Probe.)

As a commissioner, said attorney Michael Yuffee, “His dissents suggest that he has staked out a firm — even doctrinaire — approach to the application of federal energy law to facts.” (See related story, FERC Rejects Rehearing Request on SPP Order 1000 Filing.)

As chairman, consensus-building will have to become a bigger part of Bay’s repertoire, said Yuffee, a partner with Reed Smith who has worked for FERC’s Office of Administrative Law Judges and represented clients in matters with Enforcement.

“The peculiar circumstances of Chairman LaFleur moving back into a commissioner’s spot under Bay makes it likely Bay will try even harder to forge consensus amongst his colleagues, foremost with LaFleur,” Yuffee said.

Yuffee also said the unusual situation is unlikely to affect FERC staff members. LaFleur “didn’t have that much time to put her stamp on the direction of the commission. I think overall it probably will be business as usual.”

April 21, 2015February 25, 2024

Settlement over Duke Energy Companies’ Move to PJM Approved

By Suzanne Herel

The Federal Energy Regulatory Commission last week approved an uncontested settlement over the 2010 move by two Duke Energy subsidiaries from MISO into PJM (ER12-91).

FERC had rejected a February 2013 settlement over the move by Duke Energy Ohio and Duke Energy Kentucky, saying it unfairly imposed transition costs on customers that should be borne by the utilities.

The Duke companies agreed in the original settlement to reimburse American Municipal Power for any transition costs and 75% of “legacy” transmission expansion costs resulting from the move. The commission said that discriminated against other Duke customers that had not received exemptions from the transition and legacy costs, which Duke estimated at $518 million. (See FERC Rejects Settlements over ATSI, Duke Moves to PJM.)

FERC then set a hearing over how much Duke would pay to resolve its obligations for transmission expansion projects in MISO.

The new settlement, filed last October, was signed by the Duke companies and the members of AMP, Buckeye Power and East Kentucky Power Cooperative. Also signing on were the Indiana Municipal Power Agency, Dayton Power & Light, and Ohio municipalities Hamilton and Blanchester.

Under the settlement:

Effective Jan. 1, 2012, the Duke companies’ revenue requirement for wholesale transmission service provided in the DEOK Zone will not include any PJM transition costs or internal integration costs.
The Duke companies will not recover any MISO “legacy” transmission expansion costs in rates for transmission service provided since Jan. 1, 2012. Going forward, Duke will be permitted to recover 30% of MISO legacy costs.
The Duke companies’ return on equity for wholesale transmission service shall be reduced to 11.38%, including a 0.5% adder for participation in an RTO. Duke and the other signatories agreed not to seek FERC approval for a change in the ROE that would be effective before June 1, 2017.

April 21, 2015June 15, 2023

FERC Backtracks from ISO-NE Winter Reliability Order

By William Opalka

The Federal Energy Regulatory Commission on Friday backtracked from its January order directing ISO-NE to develop a market-based approach for its winter reliability program later this year (ER14-2407). (See FERC Orders Market-Based Reliability Program Next Winter in ISO-NE.)

FERC granted a request for rehearing made by the RTO, which said that gaining consensus from stakeholders would be difficult in such a tight schedule. It also argued that prematurely “overlaying” market-based solutions could create other problems and not be cost-effective. (See ISO-NE: Reverse Market-Solution Order.)

“Noting ISO-NE’s observation that a winter reliability solution may be necessary for the next several winters, we find that an expanded version of the current winter program might better produce the desired results in terms of reliability than the introduction, at this point in time, of the market-based solutions examined by ISO-NE,” FERC wrote.

While agreeing to grant the request, Commissioner Tony Clark expressed “frustration given ISO-NE’s inability or reluctance” to develop a program. “I vote in favor of today’s order as a matter of pragmatism given the practical challenges ISO New England asserts in its filing,” he wrote in a concurring opinion.

The New England Power Generators Association had argued that the region shouldn’t wait until 2018 — when the RTO’s pay-for-performance program takes effect — for a market-based solution. (See ISO-NE in Precarious Position for Winter.)

“We are disappointed,” NEPGA President Dan Dolan said. “But we are encouraged that FERC used some rather strong language, particularly Commissioner Clark, to try to put some mechanism in place, rather than just a series of one-off programs.”

ISO-NE has used out-of-market programs for the past two winters to maintain reliability.

FERC prodded ISO-NE to continue work on a market-based program, even with this reprieve. “The commission expects ISO-NE to abide by its commitment to work with stakeholders to expand any future out-of-market winter reliability program to include ‘all resources that can supply the region with fuel assurance,’ such as nuclear, coal and hydro resources,” it said.

NEPGA has complained that the winter reliability program should be resource-neutral. However, in both years of its existence, the program has relied on oil and natural gas.

April 21, 2015June 15, 2023

Bay Promotes Gasteiger, Parkinson at FERC

WASHINGTON — Federal Energy Regulatory Commission Chairman Norman Bay named Larry Gasteiger as his chief of staff and Larry Parkinson as the director of the commission’s Office of Enforcement. Bay made the announcement at his first open meeting as FERC chairman on Thursday.

Gasteiger served as deputy director under Bay when the latter headed Enforcement, and he has been serving as acting director since Bay was confirmed as a commissioner in August. Before joining Enforcement, Gasteiger was the director of the Division of Tariffs and Market Development – East in the Office of Energy Market Regulation. He also served as a deputy associate general counsel, and legal advisor to former Chairman Joseph T. Kelliher after joining FERC in 1997 from the Commodity Futures Trading Commission.

Parkinson had served as director of Enforcement’s Division of Investigations since March 2010. Before joining the commission, Parkinson held stints as deputy assistant secretary at the U.S. Department of the Interior, general counsel of the FBI and U.S. Small Business Administration, and assistant U.S. Attorney for D.C.

— Michael Brooks

April 21, 2015June 15, 2023

SPP MOPC OKs New Rules for Calculating Mitigated Offers

By Rich Heidorn Jr.

TULSA, Okla. — SPP’s Markets & Operations Policy Committee last week approved new rules on how mitigated offers will be calculated for generators that fail market power tests, choosing a solution that includes default values for variable operation and maintenance (VOM) costs.

It was the second time the group had approved new rules on mitigated offers. In December, the SPP Board of Directors rejected a proposal that had been approved by MOPC over the objections of the Market Monitoring Unit, saying it wanted a solution that had broader support.

The new proposal, which passed on a voice vote, did not win the MMU’s endorsement, however.

MMU Director Alan McQueen told MOPC that the revised proposal’s use of default VOM values was an improvement because it reduced ambiguity. He also praised the inclusion of an adder for frequently mitigated resources.

Too ‘Generic’

But he said he was concerned that the proposal “removes any reference to competitive levels,” replacing it with “variable O&M,” a term he said is too “generic” because it could refer to costs incurred over a decade. That does not conform to the Federal Energy Regulatory Commission’s mitigation premise that offers are “approximately equal to short-run marginal cost,” he said.

“It actually adds ambiguity back into the overall process that the Market Monitor is going to have to use,” he said.

McQueen said this would cause problems both when the MMU is reviewing offers from units that claim costs higher than those in the default schedule and when it and stakeholders conduct their annual review of the default levels.

SPP rules allow units found to have market power to submit market offers of up to 125% of the mitigated energy offer, which would be based in part on the VOM defaults. Thus a combined-cycle plant with a heat rate of 10 MMBtu/MWH that would be paid $41/MWh, including $6 in VOM based on the default table, could receive as much as $51.25/MWh, with an implied VOM of $16.

The ‘Next Enron’

“When is the next Enron going to be entering the SPP market?” McQueen asked. “Do you want them to be deciding what should be included in the reference level or do you want the Market Monitor, who’s listening to everybody who’s in the market?”

McQueen said that based on his discussions with generators, he believed 80% of them supported use of the defaults.

Richard Ross of American Electric Power disagreed. “I can add up fairly easily enough megawatts [opposing defaults] to figure out that it isn’t 80%.”

Nevertheless, Ross said AEP would support the new rules.

Jake Langthorn of Oklahoma Gas & Electric said he was disappointed that the default solution did not include compensation for maintenance obligations under long-term service agreements. “If the LTSAs were included, we wouldn’t have a beef with it,” he said.

Staff Supports

Although the solution did not have the unqualified support of members and the MMU, SPP Chief Operating Officer Carl Monroe said RTO staff supported the proposal because it resolved some of the longstanding disputes over VOM calculations.

Richard Dillon, SPP’s director of market design, noted that FERC’s recent State of the Markets report found the RTO’s day-ahead on-peak power price to be the second-lowest in the country last year at $40/MWh, higher than only the $39 at the Mid-Columbia pricing hub in the Pacific Northwest.

“That is a good indicator that even at 125% [of the mitigated offer] the competitive price is under market,” Dillon said.

“Columbia is all hydro. Being only behind a hydro system is a problem.”

April 21, 2015June 15, 2023

SPP Staff Plan on Kansas Transmission Project Fails to Win MOPC Endorsement

By Rich Heidorn Jr.

TULSA, Okla. — SPP staff’s recommendation that the RTO approve a 21-mile 115-kV line from Walkemeyer to North Liberal as part of a reliability solution in southwestern Kansas failed to win stakeholder endorsement last week.

Staff’s solution received almost 64% support from the Markets & Operations Policy Committee, falling short of the two-thirds needed to recommend it to the SPP board.

Staff considered three alternatives, two of which would have delayed the line indefinitely, instead relying on operating guides for Sunflower Electric Power’s 76-MW Cimarron River Station to provide relief from thermal or voltage violations.

Option 1 would add a new substation with a 345/115-kV transformer on the Hitchland–Finney 345-kV line and a new 1-mile 115 kV line from the substation to Walkemeyer at an estimated cost of $17.8 million. Cimarron would be dispatched for up to 58 MW when needed to avoid violations.

Staff’s suggestion, option 2, included the new substation and transformer but would add the Walkemeyer-North Liberal line for an additional $17.5 million, avoiding the need to rely on Cimarron for reliability.

Although option 2 had higher upfront costs, staff said it was about $1.4 million cheaper than option 1 on a net present value basis over 20 years ($68.9 million vs. $67.5 million).

Option 3, which would have relied solely on the Cimarron plant, had an NPV of $84 million and only “marginally” solved voltage violations, staff said.

Tom Hesterman of Sunflower said option 1 was the best choice, being a “statistical tie” with option 2 in NPV and having lower upfront costs.

Brian Gedrich of NextEra supported the 21-mile addition, saying “it could be the only competitive project” SPP approves in the current planning cycle.

The Cimarron plant has two natural gas-fired units: a 61-MW unit built in 1963 and a simple-cycle 15.5-MW combustion turbine added in 1967.

American Electric Power’s Richard Ross was skeptical of reliance on the aging plant, saying Sunflower was not obligated to keep it running if it requires costly repairs. He said he feared the unit could fail, necessitating the Walkemeyer-North Liberal project — but without the lead time necessary to open it to competitive bidding.

Sunflower’s Al Tamimi said the company invested heavily in the unit — adding a new cooling tower in 2014 — and had no plans to retire it. Southwestern Public Service’s phase shifter can maintain system reliability if the Cimarron plant is unavailable, Tamimi added.

“I just don’t think it’s appropriate for us to continue to rely on a unit we can’t rely on,” Ross insisted.

“That’s your opinion,” Tamimi responded. “You don’t know anything about the unit.”

“I do know that if the unit fails tomorrow and you don’t return it to service that … you’re going to turn around next year and put it right in the model as unavailable and the project … that we’re talking about here” will be required, Ross fired back. “And the difference will be whether or not you’ve pushed things out to where it’s not a competitive project.”

Antoine Lucas, director of planning, said staff would consider stakeholders’ comments before making its recommendation to the board.

April 21, 2015

PJM MRC/MC Preview

Below is a summary of the issues scheduled to be brought to a vote at the Markets and Reliability and Members committees Thursday. Each item is listed by agenda number, description and projected time of discussion, followed by a summary of the issue and links to prior coverage in RTO Insider.

RTO Insider will be in Wilmington covering the discussions and votes. See next Tuesday’s newsletter for a full report.

Markets and Reliability Committee

2. PJM Manuals (9:10-9:20)

Members will be asked to endorse the following manual change:

A. Manual 14D: Generator Operational Requirements — Changes made to comply with a recent advisory from the North American Electric Reliability Corp. on generator governor frequency response.

3. ENERGY MARKET UPLIFT SENIOR TASK FORCE (9:20-9:40)

Members will be asked to approve revisions to rules developed by the Energy Market Uplift Senior Task Force regarding treatment of combustion turbine lost opportunity costs. Under the proposal, units with start-up and notification times of no more than two hours and minimum run times of two hours would be paid lost opportunity costs if they are not dispatched. Resources with real-time start-up and notification times or minimum run times of more than two hours will not receive lost opportunity payments unless PJM bars them from running in real time to avoid transmission overloads.

SPP said its integrated marketplace resulted in production cost savings in each of the last 12 months. (See “PJM: New Rule on Lost Opportunity Costs Would Exclude 1/5 CTs” in Operating Committee Briefs, April 14.)

4. RESIDENTIAL DR MEASUREMENT AND VERIFICATION (9:40-9:50)

Members will be asked to approve Tariff and manual revisions regarding residential demand response measurement and verification, which PJM plans to file in late April. The changes, endorsed at the Jan. 22 Members Committee meeting, have been updated to include an additional delivery year. (See “Sampling to be used for Measuring Residential DR” in MRC/MC Briefs, Nov. 25.)

5. TARIFF HARMONIZATION SENIOR TASK FORCE (9:50-10)

Members will be asked to OK the draft charter of the group, formed to address inconsistencies and discrepancies in PJM’s governing documents. (See Task Force Proposed to Resolve Inconsistencies in PJM Governing Documents.)

6. GENERATOR OFFER FLEXIBILITY (10-10:15)

Members will be asked to endorse a problem statement and issue charge by Calpine seeking to allow more flexible market offers for physical generating resources. PJM is the only U.S. RTO that does not allow generators to vary their cost- or market-based offers hourly. This problem statement would consider allowing generators to revise their offers hourly to reflect changes in gas prices. (See PJM May Consider Hourly Pricing for Generators.)

7. REGIONAL PLANNING PROCESS SENIOR TASK FORCE (10:15-10:25)

On first reading, members will be asked to approve a recommendation directing the Planning Committee to develop guidelines for considering generation interconnection projects as drivers under the multi-driver transmission project approach. The committee also will be asked to place the task force on hiatus, available to be returned to operation if needed based on future rulings by the Federal Energy Regulatory Commission.

Members Committee

CONSENT AGENDA (12:05-12:10)

B. Members will be asked to approve proposed minor “non-substantial” provisions regarding financial transmission rights’ auction clearing deadlines and trading periods.

— Suzanne Herel

April 21, 2015

FERC Rejects New England Power Tx Tariff

By William Opalka

The Federal Energy Regulatory Commission on Thursday rejected tariff revisions submitted by New England Power, saying they would allow the company to exceed the commission’s limits on transmission returns on equity (ER15-418).

In Opinion 531, FERC last year ordered that the New England Transmission Owners’ total ROE, including base rate and incentives, could not exceed 11.74%, the top of the “zone of reasonableness.” (See FERC Splits over ROE.)

As a result, New England Power was required to revise the tariff governing the transmission facilities of its affiliates, Massachusetts Electric and Narragansett Electric, which it operates as a single integrated system.

But FERC ruled that the revisions the company filed would have improperly allowed it to earn returns of more than 11.74% on some of its assets as long as the average ROE was below the cap.

The commission said the company’s language “relies on the same interpretation of the term ‘total ROE’ that the New England Transmission Owners presented on rehearing in the Opinion No. 531 proceeding. The commission rejected that interpretation in Opinion No. 531-B, and we do so here for the same reasons.”

The commission also ordered the use of data from calendar year 2013, rather than 2012, to calculate the estimated decrease in revenues resulting from New England Power’s tariff revisions. The company had calculated a $2.2 million rate decrease if 2012 was used as the test year, and nearly a $2.3 million decrease based on data for 2013.