Page 1426 – RTO Insider

July 18, 2016

NYPSC Declares Moratorium on Low-Income Sign-ups

By William Opalka

The New York Public Service Commission on Thursday declared a moratorium on energy marketers signing up low-income customers, citing the inability of stakeholders to agree on consumer protection reforms (12-M-0476, et al.).

Zibelman © RTO Insider - NYPSC Declares Moratorium on ESCO Low-Income Sign-ups — Zibelman © *RTO Insider*

The commission voted 3-1 to impose the moratorium, which takes effect in 60 days.

The PSC ordered a stakeholder collaborative after its February 2015 order requiring energy service companies to guarantee that low-income consumers enrolled in utility assistance programs will pay no more under an ESCO contract than they would have as a full-service utility customer. (Alternatively, the ESCO must provide the customer with value-added products or services that do “not dilute the effectiveness of the financial assistance programs.”)

The collaborative, which included ESCOs, low-income advocates, utilities and regulators, was unable to reach a consensus that would have satisfied the aims of the order.

Commissioner Diane Burman opposed the moratorium. “The statements in the conclusion [of the order] seem to [be] more in the nature of an advocacy, rather than in a reasonable balancing of the issues that we’re supposed to deal with as regulators,” she said.

Burman said the collaborative’s report showed that some ESCOs were willing to offer savings but that the “pathway” for further discussion was cut off by the moratorium.

PSC Chair Audrey Zibelman said that the first imperative was to “do no harm” while the commission dealt with further enhancing consumer protections.

“The record is clear that low-income customers have not benefited from electric and gas supply services from ESCOs when that’s all that’s being purchased. The commission is taking steps to ensure energy affordability for low-income customers,” Zibelman said in a statement. “Unless and until these guarantees can be made, it is critical that we ensure that low-income customers are not paying any more than necessary for gas and electricity. We challenged the competitive retailers to look for ways to guarantee savings at or below the cost of utility-supplied power and gas.”

The action follows a PSC order in February 2016 that mandated savings for most retail customers. That order has been challenged by retail energy marketers. (See Court Delays New York ‘Guaranteed Savings’ Rules.)

The PSC estimates that there are more than 400,000 low-income customers served by ESCOs. Low-income customers represent about 25% of all electric customers in the state.

Customers currently served by an ESCO will revert to the host utility’s default service when their contract expires. The moratorium will last until the commission determines it can be lifted, the order states.

The Retail Energy Supply Association said it was reviewing the order with its members and legal counsel.

“If maintained, the moratorium would prevent low-income customers from accessing fixed-price energy offers that provide price certainty when compared to New York utilities’ monthly variable rates,” spokesman Bryan Lee said in a statement. “This is a benefit that is of particular value to consumers on fixed or limited incomes. By way of this order the commission has taken away the low-income consumer’s ability to enter into fixed rates just before the potentially volatile winter months when we know from experience that utility default rates can fluctuate widely in response to extreme weather.”

July 18, 2016

SPP, MISO Narrow Joint Study’s Scope

SPP’s Seams Steering Committee can expect to soon see a final scope of the next planned joint transmission study with MISO.

Adam Bell, SPP’s interregional coordinator, told the committee July 8 that the two RTOs have not nailed down the scope, but that it may not be limited to the Dakotas’ seam with the Western Area Power Administration, as MISO would prefer. The two grid operators agreed May 31 to take a “targeted” look at the newly created seam. (See “SPP, MISO Agree to Conduct ‘Targeted’ Joint Tx Study,” SPP Seams Steering Committee Briefs.)

“The scope will leverage some of the work we’ve done regionally,” Bell said.

The study is planned for completion in the first quarter of 2017.

SPP staff also told stakeholders it had filed an out-of-time intervention in an interregional planning dispute between MISO and PJM, as approved by the committee in June (EL13-88). (See “Committee Recommends SPP Intervene in FERC’s NIPSCO Docket,” SPP Seams Steering Committee Briefs.)

Staff said a MISO compliance filing removed several limitations that hampered efforts to resolve SPP-MISO seams issues, including the 345-kV and $5 million cost thresholds.

Committee Chairman Paul Malone, of the Nebraska Public Power District, reminded the committee that MISO believes the docket only applies to the MISO-PJM seam. “Why shouldn’t these same principles apply to the MISO-SPP seam?” he asked.

– Tom Kleckner

July 18, 2016

Del. Lawmakers Resolve to Fight Artificial Island Cost Allocation

The Delaware General Assembly has passed a resolution opposing PJM’s cost allocation for the Artificial Island project and creating a seven-member Cost Equity Committee to follow the issue through a planned rehearing at FERC.

Senate Concurrent Resolution 90 takes the place of a resolution approved by the state’s House of Representatives urging the Department of Natural Resources and Environmental Control to deny any easement request related to the project under the current cost allocation method. (See Del. Lawmakers Try to Block Artificial Island Plan; Project Still on Track.)

The Delaware Public Service Commission estimates that under the PJM transmission owners’ distribution factor cost allocation method (DFAX), about $354 million of the projected $410.5 million project cost will be assigned to customers in the Delmarva transmission zone, while the area stands to receive only 10% of its benefits. Following a January technical conference, FERC approved the Artificial Island project’s cost allocation on April 22. On June 21, it agreed to a rehearing. (See FERC Taking a Second Look at Cost Allocation for 2 PJM Projects.)

In addition to giving the new committee the authority to intervene in the rehearing, the measure also grants the group permission to be involved in any related court proceedings.

State and federal legislators representing Delaware, Gov. Jack Markell of Delaware, Maryland Gov. Larry Hogan and various agencies representing Delmarva ratepayers have bombarded FERC and the PJM Board of Managers with letters criticizing the cost allocation. (See Stakeholders Ask FERC to Rehear Cost Allocation Order.)

The upgrade to the New Jersey complex that houses the Salem and Hope Creek nuclear reactors involves sinking a new 230-kV transmission line under the Delaware River to Delaware.

— Suzanne Herel

July 18, 2016

UPDATED: LIPA Delays Vote on Offshore Wind Project; 90-MW Project Would be Largest in US

By Ted Caddell

The Long Island Power Authority on Wednesday delayed approving a proposed 90-MW offshore wind farm off the coast of Montauk, N.Y., that would be the largest such project in the U.S.

LIPA executives had expected an easy approval vote from its board of trustees, but they delayed the vote at the request of the New York State Energy Research and Development Authority, which also has a wind farm planned for off the Long Island coast.

The authority “has asked for a brief delay of the LIPA board vote so the project can be examined in the broader context of the Offshore Wind Master Plan, the development of which [NYSERDA] is leading for the State,” NYSERDA spokeswoman Dayle E. Zatlin said.

“The Master Plan and its forthcoming draft blueprint will inform decisions about the best way to manage this valuable resource in an environmentally responsible way and in order to obtain the lowest achievable offshore wind electricity cost for New Yorkers.”

That “blueprint,” she said, should be completed in a few weeks. “Together, these efforts are part of New York’s intent to foster greater renewable energy production, including offshore wind, on Long Island and throughout the state.”

A LIPA spokesman said a few week’s delay in the vote should have no impact on the Montauk project. “We’ve been talking off-shore wind for about 11 years on our island so the few weeks delay, in context, is not a deal breaker.”

LIPA has selected Deepwater Wind, which is already building a 30-MW project off Block Island, R.I., to develop the project.

The U.S. Bureau of Ocean Energy Management has awarded about a dozen leases for commercial wind, but only the Block Island project has begun construction.

Deepwater Wind spokeswoman Meaghan Wims said the Long Island project, to be called the South Fork Wind Farm, is part of a larger lease obtained from BOEM. “We bid 90 MW to LIPA as part of this” request for proposals, she said. “Our total capacity at that site is 1,000 MW, to be built over phases. The South Fork Wind Farm is the first phase.”

Deep Water Wind (Deep Water Wind) — View of the Block Island offshore wind project currently under construction by Deepwater, which was selected to build the Montauk project.

Montauk Project to Use 15, 6-MW Turbines

Deepwater will install 15 6-MW turbines about 30 miles off the coast of Montauk. Two 5-MW lithium-ion batteries will replace transmission investments that otherwise would be necessary. If all goes well, construction work could begin by 2021, with an operational date of December 2022, Falcone said.

“It is part of our goal to attain 400 MW of renewable energy, as part of the New York Clean Energy Standard, by 2023,” LIPA CEO Tom Falcone said in an interview Friday.

“We have an area of our service territory, East and South Hampton, with a lot of load growth, and we needed to address it in some way,” Falcone said. He said LIPA considered a transmission project to address the growing load, but after reviewing responses to its RFP, it determined the offshore wind project fit all the requirements.

“It’s the right project, the right size, and we can land in the right price area,” he said. Falcone said the project will cost a typical residential customer about $1.20/month.

Earlier offshore wind proposals were much more expensive than that, he said. Now, the cost of offshore wind is about the same as utility-scale solar — a resource not suited for crowded Long Island.

“I am not aware of any other utility that has signed a contract on a utility-scale project like this,” Falcone said. “We don’t have many other options” when it comes to renewable energy, he said. “On Long Island, land is constrained. But we have this tremendous offshore wind resource, thousands of megawatts. It is a tremendous resource.”

Lead Time Reduced

Falcone said much of the federal review process necessary for the Montauk project has already been done by Deepwater, which could save up to three years in the lead time for the project. “That was one thing that was particularly attractive” about the Deepwater plan, he said. “They are ready to go.”

Offshore wind projects need to be reviewed by BOEM to ensure they don’t encroach on commercial shipping areas or fishing grounds.

Community opposition has hindered other offshore wind projects on the East Coast. A 468-MW facility proposed off the coast of Massachusetts is tangled up in opposition from residents and no firm construction start date has been set.

Since news of its project got out, said LIPA Spokesman Sid Nathan, the authority has received dozens of messages of support from lawmakers, business owners and labor leaders. “We don’t expect community opposition of the proposal,” Falcone said.

“New York is boldly leading the way on a clean-energy revolution that will transform the nation’s energy future,” Deepwater CEO Jeffrey Grybowski said. “There’s real momentum for offshore wind in the United States, and Long Islanders are leading the charge.”

Currently, the largest offshore wind facility in the world is the 630-MW London Array, a 175-turbine facility off England’s eastern coast, in the outer Thames Estuary. DONG Energy is building tandem wind farms off the Dutch coast that will total 700 MW.

July 18, 2016

PJM Defends Analysis of Competitive vs. Regulated Markets

By Suzanne Herel

PJM CEO Andy Ott released a letter July 8 defending the RTO’s paper on competitive markets, saying that while it believes its markets are effective in both regulated and competitive retail structures, it did not conclude that any market outcome was superior to cost-of-service regulation.

Andy Ott, PJM © RTO Insider — Andy Ott, PJM *© RTO Insider*

“Instead, our analysis supports the hypothesis that markets lead to more cost-effective and economically efficient outcomes in managing new entry and exit of resources,” Ott wrote. “But this is purely an economic observation and is not to suggest that markets lead to the ‘best’ or ‘most superior’ outcomes for all parties in all circumstances.” (See PJM Study Defends Markets, Warns State Policies Can Harm Competition.)

Ott also indicated PJM would consider adding multiyear commitments to the capacity market’s current one-year contracts, which are procured three years in advance.

AEP, FirstEnergy Challenge

A coalition of generators led by American Electric Power and FirstEnergy challenged PJM’s analysis in a letter May 19, saying it presented a skewed view of the benefits of competitive constructs compared with the traditional regulated model. (See Generators Rebut PJM Study on Investment in Competitive Markets.)

AEP and FirstEnergy were joined by Dayton Power and Light, Duke Energy Ohio and Kentucky, Buckeye Power and East Kentucky Power Cooperative.

PJM’s Board of Managers commissioned the study after AEP and FirstEnergy asked Ohio regulators, and Exelon asked Illinois legislators, for help in supporting money-losing generators. (See PUCO Staff Recommends $131M Annual Rider for FirstEnergy.)

On July 7, Exelon officially notified PJM of its plan to close its Quad Cities nuclear plant on June 1, 2018, citing a lack of action by Illinois legislators. It also intends to shutter its Clinton station next year.

In his letter, Ott said, “As a threshold matter, we agree that cost-of-service regulation has managed the entry and exit of generation resources in a highly reliable manner over many decades. Indeed, as we noted in Part 2 of the PJM paper, regulated environments offer a forum to balance social, political and environmental interests alongside electricity costs to the consumer. … PJM also believes, however, that markets result in a more cost-effective and economically efficient approach to procuring adequate generating resources.”

Coal Retirements not Unique

Ott acknowledged concerns over generation retirements in PJM, but he said, “The retirement of coal generation and its replacement with combined cycle natural gas power plants is happening across this country; it is not unique to PJM.”

He also combatted generators’ assertion that PJM’s competitive markets owe their success to legacy assets and that it has relied on its pre-existing reserve margin for a decade.

“PJM forward projections indicated installed reserve margins were declining and would fall below 16% in 2008. In order to address these concerns, PJM proposed and implemented the [Reliability Pricing Model] forward capacity construct under which the declining reserve margin trend reversed,” he wrote. “Despite unprecedented forces changing the generation fuel mix in this country, PJM’s forward capacity market has maintained robust installed reserve margins. For the 2019/2020 planning year, PJM is carrying an approximate 22% reserve margin.”

Fuel Diversity

The regulated model, he said, lends itself to sacrificing some of that objective in favor of others, including promoting fuel diversity.

“While the recent investment trends have actually made PJM’s aggregate fuel mix more diverse over the past decade, PJM understands the concern that we need to analyze and quantify any potential operational or reliability challenges that may occur if the PJM region trends toward a very large percentage of gas-fired generation in the future,” Ott wrote. “PJM commits to perform such an analysis and will share results with stakeholders by first quarter of 2017.”

Multiyear Commitments

He added that PJM agrees in concept that the capacity market would be strengthened by the addition of some multiyear commitments.

“On this point, we agree that through bilateral agreements or market design changes, the market would be served by better options to lock-in price [and] manage risk and volatility for at least a portion of the supply portfolio,” he said.

In contrast with the negative reception it received from utilities in Ohio and Kentucky, PJM’s paper was lauded by the PJM Power Providers Group (P3) and a coalition of 16 independent power producers, including Calpine, Dynegy, NRG Energy and Talen Energy in letters last month.

“When markets are allowed to work, and are not undermined by out-of-market interventions or uneconomic new entry, consumers across the region will continue to see highly reliable service at the most efficient price,” wrote the IPPs.

Both P3 and the IPPs noted the new natural gas capacity added or proposed in the past five years.

“The IPP sector continues to lead this new investment, and the competitive PJM market structure has been the enabling platform on which these investment decisions have been made,” the IPPs said. “What PJM’s markets have not done — and should not do — is provide protection for certain suppliers who want to be shielded from market risk.”

July 18, 2016

SPP Strategic Planning Committee Briefs

RAPID CITY, S.D. — The Transmission Planning Improvement Task Force’s recommendations to streamline SPP’s transmission planning process won unanimous approval from the Strategic Planning Committee and the Markets and Operations Policy Committee last week.

If the recommendations win final approval from the Board of Directors next week, SPP will combine the Integrated Transmission Planning (ITP) near-term and 10-year assessments and NERC transmission planning (TPL) assessments into a single 10-year study that will produce an annual transmission expansion plan addressing reliability, economic and policy needs.

The new process will begin in September 2017, with its first results unveiled in October 2019. SPP will complete the 2017 ITP10, the 2017 and 2018 ITPNTs and conduct TPL assessments during the transition period.

NextEra Energy Transmission’s Brian Gedrich, the task force’s chair, said the new process will yield more accurate and forward-looking results.

“It’s a holistic approach, the opposite of the sequential way we do it now,” Gedrich told the SPC. “A lot of manpower resources are spent to provide [transmission-planning] information for you and the board. This will free up time so folks can do analysis … that will actually be actionable.

“No one was happy with the process. Today, all you do is take a 10-year look ahead. How can you possible see what is happening in real time, when all you look out is 10 years?”

Gedrich said building the initial future cases would require two to four additional full-time equivalents and $350,000 to $400,000 in consulting costs, depending on whether staff analyzes two or three futures. The task force recommended two futures.

“What are we getting out of this additional cost?” asked SPP Director Harry Skilton, who chairs the RTO’s Finance Committee. “I hear you say more efficiencies, but what tangible benefits do members get?”

ITC Holdings’ Marguerite Wagner agreed the benefits can be difficult to quantify.

“We spend hundreds of millions of dollars on transmission, and we see congestion in the same areas,” she said. “We expect this new process to be more granular, thus leading to potentially better solutions and outcomes.”

“As you do the same thing over and over, I think you will gain efficiencies. Right now, as we start and stop, you lose a lot of time,” Gedrich said.

Skilton seemed satisfied with the responses. “If in the judgment of the membership it will get better results, address congestion in the near term and improve the planning process … that’s a helluva accomplishment,” he said.

The task force’s other recommendations included:

Standardizing the ITP’s scope and developing a streamlined assumptions document;
Developing a single, base reliability powerflow model that will be used for all planning processes;
Adding accountability with mechanisms designed to promote timely data exchanges, reviews and approvals; and
Limiting the initial 2019 study scope to two study futures to help facilitate the move to the new planning process.

Export Pricing Task Force Given the Go-Ahead

The committee unanimously accepted staff’s recommendation to create an export-pricing task force to research SPP’s Tariff and FERC policy and evaluate how best to take advantage of the RTO’s abundant variable energy resources.

SPP Boardmember Phyllis Bernard, SPP VP Michael Desselle, Golden Spread Electric Co-Op's Mike Wise lead SPC meeting (RTO Insider)-web — Left to right: SPP board member Phyllis Bernard, SPP VP Michael Desselle, Golden Spread Electric Co-Op’s Mike Wise © *RTO Insider*

The task force would make recommendations on establishing “equitable and nondiscriminatory” rates to address recovering incremental transmission and facility costs needed to export and import electricity, and “how to avoid paying for it on the back of SPP ratepayers — which will be difficult to do,” said Sam Loudenslager of SPP’s regulatory staff.

Loudenslager said the SPP region currently has 22,000 MW of variable resources in its queue and not yet in service.

SPP’s Corporate Governance Committee, which doesn’t meet until late August, will have to approve the task force’s formation.

Dogwood Energy’s Rob Janssen suggested the task force’s representation include members experienced with life on the seams.

“We have to remember we have members with loads on both sides of the border, who move power any given day or time,” he said.

“If you can’t get the money right, you can’t get anything done,” SPP Director Phyllis Bernard said. “This is one of those task forces focusing in on how to get the money right. There are genuine legal problems here, and absent federal direction, export pricing has to be the solution.”

Asked by SPC Chairman Mike Wise of Golden Spread Electric Cooperative whether the task force would develop a marketing campaign to “advertise our energy,” Loudenslager responded, “I’m not a marketing guy.”

– Tom Kleckner

July 18, 2016

PJM, Retail Marketers Intervene in Dayton Power Subsidy Bid

By Rory D. Sweeney

PJM and the Retail Energy Supply Association want a say in Dayton Power and Light’s plan to keep its coal-fired plants running.

Both organizations have filed motions to intervene in DP&L’s “electric security plan” application before the Public Utilities Commission of Ohio. If their past actions are any indication, they will voice objection to the plan, much as they did in similar cases involving FirstEnergy and American Electric Power, which are Ohio’s two largest electric utilities. (See PJM Looking at AEP, FirstEnergy PPAs; Critics Join Forces.)

DP&L’s application proposes a 10-year reliable electricity rider (RER), which would help parent company AES continue operating its fleet of coal-fired plants. Under the rider, DP&L would agree to acquire generation from the shares another AES subsidiary owns in the Ohio Valley Electric Corp. and the Conesville, Killen, Miami Fort, Stuart and Zimmer plants — all baseload coal-fired facilities DP&L used to own but was required to sell under its current ESP.

The rider would further stipulate that the difference between the revenue requirements of each plant and its expected revenue would be calculated annually. Depending on the outcome of the calculation, customers would receive a credit or a charge.

PJM, RESA, Dayton Power and Light — Kyger Creek Power Plant

In announcing the application, DP&L estimated that, if approved, the first year of the rider in 2017 would result in an additional $1.21 charged to each monthly bill but “contribute an estimated $26.5 billion in positive economic benefits for Ohio.”

In their filings, PJM and RESA said approval of the plan would have market-wide impacts.

“The commission’s decision in this matter will affect the viability of the competitive retail electric market in DP&L’s service territory,” RESA said in its filing.

“The nature and extent of PJM’s interest is to ensure DP&L’s RER proposal will not negatively impact PJM’s ability to administer efficient and competitive wholesale energy, ancillary service and capacity markets, and maintain the reliability of the transmission system in the PJM region,” PJM’s filing stated.

DP&L’s plan has drawn criticism from environmental groups, including the Ohio Environmental Council and the Environmental Defense Fund. Both groups are also contesting similar proposals from FirstEnergy and AEP.

The companies are “cherry-picking some of their worst plants, and they’ll put those in a package and they’ll say that the state of Ohio needs these for jobs and economic development,” said John Finnigan, a lead attorney with EDF.

“It’s a subsidy for these plants. These plants are out of the money.”

Under its current ESP, DP&L was required to divest its generating assets. AES decided in 2014 to retain the Dayton-area power plants, which were nearly 3,500 MW at the time. The generation was sold to another AES subsidiary, AES Ohio Generation.

Both AES Ohio and DP&L are overseen by DPL, another AES subsidiary. Today, DPL serves (through DP&L) approximately 515,000 customers in 24 counties throughout West Central Ohio and operates (through AES Ohio) 3,066 MW of generation, 2,078 MW of which is coal-fired.

DP&L said it was reviewing the petitions to intervene. “Once a thorough review is complete, we will explore all options for our next steps,” said spokeswoman Mary Ann Kabel.

July 18, 2016

FERC OKs 9.8% ROE in Transource Settlement

FERC last week approved Transource Kansas’ settlement with the Kansas Corporation Commission, under which the company will receive a 9.8% base return on equity for any transmission facilities in SPP (ER15-958).

The company will earn a total of 10.3%, including a 50-basis-point adder previously approved by the commission for participation in an RTO.

FERC trial staff supported the settlement in an April 27 filing but noted that the agreement was silent on the top end of the discounted cash flow (DCF) zone of reasonableness. “Therefore, if Transource Kansas (or its affiliates) makes a future request seeking additional ROE incentive rate adders for a specific transmission project, the commission’s approval of this settlement will not eliminate the need for the applicant to make a Section 205 filing that includes a two-step DCF analysis establishing a zone of reasonableness, the top of which will cap any total ROE,” staff said.

Transource Kansas is a subsidiary of Transource Energy, a joint venture between American Electric Power and Great Plains Energy.

– Rich Heidorn Jr.

July 18, 2016

FERC Rejects PJM Cost Allocation on Dominion Project

By Rory D. Sweeney

FERC accepted PJM’s cost responsibility assignments for 33 of 34 baseline upgrades, ordering the RTO to change the billing for one Dominion Resources project and revise its Operating Agreement to address inconsistencies (ER16-736, EL16-96). PJM’s Board of Managers approved the projects in December as additions to its Regional Transmission Expansion Plan.

The commission rejected the cost assignment on Dominion’s 500-kV Cunningham-Elmont rebuild project (b2665), saying it should be funded solely by Dominion ratepayers rather than spread across the region.

FERC said PJM’s proposal was inconsistent with its February order that transmission owners should pay all of the cost of projects that solely address a TO’s local planning criteria. (See FERC Does 180 on Local Tx Cost Allocation in PJM.)

The commission gave PJM 30 days to submit a compliance filing “to reflect the appropriate cost responsibility assignment” — allocated to the transmission owners’ zones via the solution-based distribution factor (DFAX) method.

PJM had proposed the DFAX method for 30 other low-voltage projects addressing local planning criteria. Costs of the three other projects — involving 500-kV or double-circuit 345-kV lines — will be allocated 50% on a regionwide, postage-stamp basis and 50% via DFAX.

Commissioner Cheryl LaFleur dissented on the b2665 decision, noting it involved a 500-kV line. “High-voltage lines in PJM have inherent regional benefits that warrant some measure of regional cost allocation,” she said.

She also reiterated concerns she’s noted previously that incumbent TOs may be delaying action on transmission upgrades until the projects become immediately necessary and therefore no longer subject to competitive bidding under Order 1000.

“It is important that incumbent transmission owners report their transmission needs to PJM in a timeframe that allows PJM to meet them in a timely manner, and open them to competitive bidding requirements if they are not in fact immediate,” she wrote. “If it appears over time that incumbent transmission owners may be postponing identification of transmission needs to avoid competitive bidding, further action may be needed to ensure that customers receive the intended benefits of Order No. 1000 planning processes.”

OA Inconsistencies

The commission also ordered PJM to correct inconsistencies in its Operating Agreement.

The agreement requires that the transmission owner be the designated entity when 100% of the project costs are allocated to the transmission owner’s zone, as in Form 715 projects. However, another section of the Operating Agreement appears not to exempt Form 715 projects from the competitive proposal process. FERC required PJM to clarify that exemption and the process the RTO will follow in these situations.

The second inconsistency involved determinations for how proposals qualify as “immediate-need” reliability projects. The commission found it “proper” for PJM to use the date a reliability need must be addressed rather than the expected in-service date and said the agreement needs to reflect that.

FERC gave PJM 30 days to submit revisions or explain why such changes are unnecessary. Parties interested in intervening must file notices within 21 days.

The commission expects to file a final order on this proceeding with 180 days from publication in the Federal Register.

July 18, 2016

PJM Operating Committee Briefs

VALLEY FORGE, Pa. — Two 345-kV lines that were knocked out when a tornado leveled four transmission towers in Commonwealth Edison territory on June 22 were back online as of July 12, PJM’s Chris Pilong told the Operating Committee last week.

The twister hit near LaSalle, in North-Central Illinois, around 10 p.m., he said, tripping the Plano 0101 and Plano 0102 lines.

In response, a number of generators in the ComEd zone and other PJM areas manually reduced their output.

The effect of the eight-day outage was localized, with only minimal congestion of $136,000, Pilong said.

“There were no emergency procedures, nothing too crazy,” he said.

On June 30, the Plano 0101 was restored using a temporary structure while the other line remained out of service. On July 10, Plano 0101 was moved onto a permanent structure, Pilong said. By the end of July 12, both lines had been restored.

EKPC Forecast Errors Puzzle Operators

In other reports on operations, Pilong noted that the Eastern Kentucky Power Cooperative zone has been showing an unusually high percentage of peak load forecast errors.

“There is something going on there. We’re trying to dig into it and nail down who’s high — is it just one entity?” he said. EKPC has 16 member cooperatives.

“It is a cause for concern, but it doesn’t violate NERC criteria,” Committee Chairman Mike Bryson said. “When we see a significant change like that, we want to understand what’s causing it and see if we have to make any adjustments.”

The average RTO-wide load forecast error performance for June was 2.57%, within the goal of 3%. EKPC’s was highest, at 3.6%, down from 4.7% for the first quarter of the year.

CP Units to be Ineligible for Winter Testing; May Choose to Self-Schedule

Generators that have cleared as Capacity Performance will be ineligible to participate in the PJM-scheduled cold weather tests beginning this winter under changes to Manual 14D that the OC will be asked to endorse next month.

Non-CP resources will be eligible for testing and will be compensated as a pool-scheduled resource on their cost-based schedule.

CP resources may elect to self-schedule tests, enabling them to be compensated as a self-scheduling resource according to the Tariff.

Regardless of how the tests are performed, PJM wants to keep track of the results and is asking that they be submitted within five days of testing.

“When it included all units, there were a number of unit owners that told us they were testing outside of the program,” Bryson said. “That’s one of the things we’re trying to capture.”

The changes came after generators last month opposed a proposal to keep CP units in the testing but end their compensation. All capacity resources will be required to be CP beginning in the 2020/21 delivery year. (See “PJM Plans to End Compensation for CP Units Participating in Winter Testing,” PJM Operating Committee Briefs.)

— Suzanne Herel