Page 1685 – RTO Insider

November 15, 2013

FERC Staff Skeptical on PJM Demand Response Changes

Federal Energy Regulatory Commission staff signaled Wednesday that the commission may require PJM to change rules requiring demand response providers to provide “sell offer plans” in order to participate in capacity auctions.

At a nearly four-hour technical conference, members of FERC’s Office of Energy Market Regulation (OEMR), Office of General Counsel (OGC) and Office of Energy Policy and Innovation (OEPI) questioned a three-member panel including PJM Executive Vice President of Markets Andy Ott. The subject was the demand response “plan enhancements” approved by stakeholders in June and submitted to FERC in August (ER13-2108). (See PJM Demand Response Providers Decry Scrutiny, “Freight Train” of Changes)

Ott said the offer plans — and a requirement that they be certified by a corporate officer — were needed to prevent DR providers from gaming the capacity market by selling in the Base Residual Auction and buying out their obligations at much lower prices in Incremental Auctions.

Ott was backed by Kenneth Carretta, managing director of power market development for PSEG Energy Resources and Trade, LLC, who represented generators on the panel. Carretta said the officer certifications were similar to those required of generators offering capacity.

But the third member of the panel, Frank Lacey, vice president of regulatory and market strategy at demand response aggregator Comverge Inc., said PJM’s changes are unnecessary and will stunt the development of DR.

Commission Order

The technical conference was ordered by the commission Oct. 1 when it suspended PJM’s proposed changes to its Tariff and Reliability Assurance Agreement for five months pending further investigation. The commission said more investigation was needed to determine whether PJM’s filing cleared the “just and reasonable” threshold.

The commission’s two Republican members, Philip Moeller and Tony Clark concurred in the order but said their “initial assessment is that PJM’s filing represents a balanced approach for resolving its reliability concerns.”

About 50 PJM stakeholders and attorneys listened during Wednesday’s conference, including Market Monitor Joe Bowring and PJM General Counsel Vince Duane. Commissioner Moeller and policy advisor Jason Stanek also attended part of the conference.

Auction-Performance Link

FERC Staffers questioned why PJM could not address its concerns under current rules and pressed for evidence of a linkage between auction behavior and reliability threats.

Ott said some DR aggregators provide PJM only “cursory” one-paragraph assurances of their intent to procure resources to meet their obligations. They “tend to be the ones that replace a lot” of capacity in the incremental auctions.

“There is no evidence that there’s been a capacity shortfall because of incremental auction purchases,” Lacey said. “…There is no evidence that DR won’t perform.”

Demand response “has consistently delivered,” Ott acknowledged. “It has been there when called.”

Chris Young, of OEPI, questioned whether PJM was being reasonable in the information it seeks to require from DR providers. “You don’t expect generators to purchase steel before” winning a capacity contract, he noted.

Michael Goldenberg, of OGC, asked how PJM could distinguish between good and bad seller plans, wondering why the RTO hadn’t filed “fact-based parameters instead of this kind of reciprocal analysis.”

Certifying Intangibles

Lacey complained that the proposed requirements were speculative and lacked clear definitions.

PJM’s officer certifications for transmission and generation are based on tangibles, such as the percentage of right of way acquired, Lacey said. “That’s an easy certification to make. Either it’s true or it’s not true.”

In contrast, DR providers are being asked to certify plans to acquire customers three years in advance when most customers only sign one-year contracts with their Curtailment Service Providers. “Customers don’t look four years in advance,” he said.

“There’s nothing that says if the rules change we can get out. Or if the economy changes.” Absent such a definition, Lacey said, DR providers risk getting referred to FERC for enforcement action, “and that is a very scary thing,” he said.

“We’re asking for due diligence,” Ott responded. “We’re not asking them to predict the future.”

PJM is intending only to remove the “incentive and opportunity for certain DR providers to speculate,” Ott added. “Then they’re not delivering anything. They’re just taking money out of the market.”

Carretta added: “There’s a lot of rules generators don’t like — that don’t agree with our business models.”

RPM Shortcomings

Ott said the Reliability Pricing Model (RPM) is an “administrative construct” and not a true market. “The IAs simply are not going to be this wonderful liquid market to… discipline behavior,” he said.

Lacey responded: “Does RPM work? If it does let it go” and prices will recover. “If it doesn’t work then we have a much bigger problem.”

Lacey said Comverge both buys and sells capacity in the Incremental Auctions, acknowledging his company had profited by buying out of some obligations in the IAs. “We have obligations to shareholders too,” he said, adding: “We’re not going to buy out of our entire position — that’s our business.”

`Overprocurement’

Several audience members also made comments during the conference.

Ed Tatum, of Old Dominion Electric Cooperative, said one reason for the disparity in prices between the Base and Incremental auctions is that PJM has procured too much capacity in the BRA — imposing excessive costs on load. The IAs offer load an opportunity to at least “get 20 cents back on the dollar,” he said, addressing the FERC staffers. “I ask you not to take that away.”

Market Monitor Joseph Bowring, however, said “PJM’s not going far enough” in its actions to end arbitrage opportunities.

Post-Conference Comments

Post conference comments in the case are due Nov. 27, with reply comments due a week later on Dec. 4.

The commission must weighing PJM’s filing against Congress’ direction in the 2005 Energy Policy Act that “unnecessary barriers to demand response participation in energy, capacity and ancillary service markets shall be eliminated.”

November 15, 2013

Members OK Capacity Import Limit; Prices May Rise

The Markets and Reliability Committee overwhelmingly approved revised methodology that will limit external generation resources in next year’s base capacity auction to 6,200 MW – a 17% drop from the volume of imports that cleared in May’s auction.

The proposal, which will also set five import zones with their own limits, won 87% support in a sector-weighted vote, sending it on to the Members Committee for a final vote next week.

Impact Uncertain

The change will put upward pressure on capacity prices. How much it will help generators inside PJM, who have been hurt by the fall in capacity prices resulting from competition from both imports and demand response, is unclear.

In response to a question from Susan Bruce, representing the PJM Industrial Customer Coalition, PJM Executive Vice President for Markets Andy Ott said he believed the import limit will be “smaller magnitude in dollars” than a demand response proposal that members rejected yesterday. The DR proposal would add about $1 billion a year in capacity costs according to PJM’s simulations. (See related story PJM Wins One, Loses One on Capacity Market Changes)

In response to a later question from the Maryland Public Service Commission’s Walter Hall, Ott gave a response that seemed to undercut that certitude, saying “We do not have an estimate, nor could we get an estimate, as to the import limit” impact.

There are a number of variables that could affect future clearing prices, including the strength of the economy and the volume of demand response. DR offers dropped 27% in May from the 2012 auction. A rebound in DR offers next year could at least partially offset the import restriction.

Import Growth

The new methodology grew out of concerns that PJM might lack sufficient transmission capacity to accommodate its growing volume of capacity imports. Cleared imports grew from about 3,000 MW to more than 4,500 MW in 2009-2012 before more than doubling to nearly 7,500 MW this year.

Based on current assumptions for 2018, PJM’s First Contingency Incremental Transfer Capability (FCITC) is 9,700 MW. Because 3,500 MW of the import capability must be reserved for the Capacity Benefit Margin, the cap on imports clearing in the BRA would be 6,200.

The new rules set both overall limits and individual limits for five “external source zones.” Generators in the five zones will compete against each other until the individual caps or the overall limit is hit.

External generators with firm transmission that commit to providing capacity in future auctions and have pseudo-ties allowing PJM to control their dispatch will not count against the limits as long as total imports don’t exceed the total firm service that has been granted for that delivery year.

November 15, 2013

PJM Wins One, Loses One on Capacity Market Changes

Members yesterday approved PJM’s methodology for limiting capacity imports but soundly rejected the RTO’s proposal to change the way demand response clears in the annual capacity auction.

The import cap passed easily, with 87% support in a sector-weighted vote of the Markets and Reliability Committee. (See related story Members OK Capacity Import Limit; Prices May Rise.)

But PJM was unable to win support for its view on how demand response should be treated in the auction, as members signaled a preference for an alternative by state consumer advocates and the Southern Maryland Electric Cooperative (SMECO). The alternative fell narrowly short of the two-thirds plurality needed to send it to a final vote by the Members Committee, leaving the issue in limbo.

Load Rebels

Representatives of public power, industrial load, retail marketers and demand response aggregators teamed up in a rebuke to PJM management, which had rejected the SMECO/Advocates proposal as not addressing the RTO’s reliability concerns.

The PJM proposal, which was backed by generation representatives, received only 37% support in the sector-weighted vote, while the alternative won 64%. PJM’s proposal had received support of nearly three-quarters of voters at the Capacity Senior Task Force, with 95% calling for a change in the status quo.

As has happened in the past, however, proposals that seem to have wide support at the subcommittee level — where utilities with PJM memberships for multiple subsidiaries can dominate voting — can falter when the vote is weighted by sector at the senior committees.

Only generation owners (11-3) and transmission owners (9-3) supported the PJM proposal. End-use customers (0-13) electric distributors (2-29) and other suppliers (6-20) were overwhelmingly opposed. The coalitions were flipped for the SMECO/Advocates proposal. (See vote tally.)

No Members Committee Vote

PJM Executive Vice President for markets Andy Ott, who had flatly rejected the SMECO/Advocates proposal at last month’s MRC meeting (see States, LSEs on Collision Course with PJM over DR Changes), said after the votes that PJM management would not put the issue on the agenda for next week’s Members Committee meeting.

The PJM Board of Managers could act unilaterally to send the PJM proposal to the Federal Energy Regulatory Commission for approval. Given the lack of stakeholder support, however, it would do so at the risk of being rejected. FERC has already signaled uneasiness with a previous change to DR that was approved by stakeholders. (See related story on Wednesday’s technical conference on PJM’s DR “plan enhancements.”)

Impact of PJM's Proposed Changes (Source: PJM Interconnection, LLC) — Impact of PJM’s Proposed Changes (Source: PJM Interconnection, LLC)

Under current rules, 4.8% of PJM’s reliability requirement can be filled with limited demand response, with higher levels possible if excess capacity clears against the sloped Variable Resource Requirement (VRR) demand curve. PJM wants to reduce the 4.8% by all of the 2.5% Short-term Resource Procurement Target (STRPT) for a net of 2.3%.

The SMECO/Advocates proposal would reduce the 4.8% by only a portion — to be determined — of the 2.5% holdback.

Failed to Make Reliability Case

Before the vote, several members said PJM officials had failed to make their case: That the current method of clearing DR risked recreating a vertical demand curve that would lead to boom-bust capacity markets and undermine reliability.

“I don’t believe there’s a real issue with the demand curve,” said Bruce Campbell, of demand response aggregator EnergyConnect. Ken Schisler, of DR aggregator EnerNOC, called the proposal a “radical departure.”

Bill Schofield, who represents the PJM Public Power Coalition, said there was a “diversity of opinion” among coalition members but that most thought PJM’s proposal “unnecessarily conservative.”

Compromise Attempt

After the votes, the committee broke for lunch, then returned for first reads on three issues that will be brought to a vote next week. (See next week’s MRC/MC Preview for details.)

At the end of the meeting, Steve Lieberman of Old Dominion Electric Cooperative (ODEC) gave a presentation on what he called a compromise between the PJM and the SMECO/Advocates proposals.

The proposal was greeted skeptically by generation representatives and PJM.

Jason Barker, of Exelon, said it failed to address the problem identified by PJM and was uncompetitive because it values all year-round resources, including annual DR, the same as limited products.

PJM officials said they didn’t understand how the proposal would work without reducing the amount of annual DR. “It’s almost like you’re trying to squeeze a stone,” said Ott.

But PJM’s Jeff Bastian said that PJM might consider incorporating one aspect of the ODEC proposal into PJM’s plan.

Market Monitor Joe Bowring said that would be a mistake. “From our view, the PJM proposal was a compromise that didn’t go far enough. Attempts to move away from that is a move in the wrong direction.”

November 12, 2013

MRC Preview

Below is a summary of the issues scheduled to be brought before a special meeting of the Markets and Reliability 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 proceedings and will provide a full report.

ENDORSEMENTS/APPROVALS

2. MAXIMUM IMPORT LEVEL (9:10-10:00)

Members will be asked to approve a methodology for limiting the volume of imports that clear in future capacity auctions. (See Import Cap Approved Capacity Prices May Rise)

3. CLEARING OF LIMITED DEMAND RESPONSE (DR) RESOURCES (10:00-11:00)

Members will be asked to approve PJM’s proposal to cap the volume of Limited Demand Response that can clear in the capacity auction.

PJM’s proposal won support of 75% of the voters at the Capacity Senior Task Force, besting three alternatives proposed by states and demand response aggregators. None of those bids won support of more than a quarter of the 182 voters. (See States, LSEs on Collision Course with PJM over DR Changes.)

PJM says the current rules result in a vertical demand curve that leads to boom-bust cycles in which the system “oscillates” between being long on capacity, with low prices, and being short on capacity with high prices.

Impact of PJM's proposed changes on clearing of limited DR (Source: PJM Interconnection, LLC) — Impact of PJM’s proposed changes on clearing of limited DR (Source: PJM Interconnection, LLC)

A simulation found that PJM’s proposal would have increased total costs by $1 billion over actual costs in the 2015/16 auction and $800 million for 2016/17 while reducing the volume of limited DR clearing in the two years by 64%.

An alternate proposed by Southern Maryland Electric Cooperative (SMECO) and state Public Advocates proposal would have increased costs by less than 1% over the two years while reducing the volume of limited DR by about one-fifth. (See Demand Response Changes Could Cost $1B Annually.)

PJM officials said their proposal will ultimately save consumers money by ensuring adequate capacity and keeping energy market prices low.

PJM wants the new rules in place by February, when the RTO must post planning parameters for the 2014 Base Residual Auction. If no proposal wins support of two-thirds of stakeholders in a sector-weighted vote of the MRC, the PJM Board of Managers can unilaterally decide to file the proposed changes with the Federal Energy Regulatory Commission.

FIRST READINGS

The MRC also will hear first reads on three other proposals that will be brought to a vote at a second MRC meeting Nov. 21.

4. DEMAND RESPONSE AS AN OPERATIONAL CAPACITY RESOURCE (11:00-1:30)

Members will be presented with the results of a Capacity Senior Task Force votes concluding today on six proposals to change the way DR is dispatched. (See Too Many Choices: DR, Auction Changes Go To Vote.)

5. REPLACEMENT CAPACITY / PROSPECTIVE CAPACITY RESOURCE INCENTIVES (1:30-2:30)

Members will be presented with the results of a Capacity Senior Task Force votes concluding today on 12 proposals to prevent speculation in the capacity auctions. (See Too Many Choices: DR, Auction Changes Go To Vote.)

6. PRICE FORMATION AND RESERVE REQUIREMENTS DURING HOT WEATHER OPERATIONS (2:30-3:30)

PJM will present a proposed problem statement and issue charge to consider increasing reserve requirements under certain circumstances. The revised methodology could increase reserve and real-time energy while reducing uplift. (See PJM: Change RT Pricing)

November 12, 2013

MIC Begins Work on Curve-Smoothing, Gen Adders

The Market Implementation Committee began work last week on an initiative to create more accurate capacity market price curves and a recommendation by the Market Monitor to eliminate adders for frequently mitigated units (FMU).

Load Curves

An issue charge proposed by Exelon in June calls for modifying the algorithm used for publishing supply curves from the annual capacity auction.

Exelon and other stakeholders are seeking improvements to the supply curve currently produced by the Market Monitor, which masks individual price-quantity offers. Exelon said the current curves — a compromise intended to balance transparency against disclosure of commercially sensitive data — aren’t accurate enough for use in analysis. (See Capacity Supply Curve Review Gets MIC OK.)

The current method is the result of a Federal Energy Regulatory Commission order in a dispute over PJM’s proposal to publish price-quantity pairs after the 2010 Base Residual Auction.

One generator representative noted that the capacity auction results have far-reaching implications for generators and other market participants. Because the curves are imprecise and not released until several days after the auctions, “we are sometimes at a disadvantage to explain certain outcomes” in the auction, he said.

Anachronistic

The committee also began work on a problem statement and issue statement to consider whether to end extra compensation for generators that frequently run on cost-based offers under market power mitigation rules. (See PJM Reconsiders Adders on Cost-Capped Generators.)

Market Monitor Joe Bowring called for the review, saying the adders are no longer needed because of the introduction of the capacity market in 2007 and changes to scarcity pricing rules in 2012. The adders are “anachronistic” Bowring told the committee Wednesday.

He softened his previous statements somewhat, saying that PJM might need to keep the adders for a few “outliers.”

Less than 1% of megawatts sold last year were offer capped. But because the affected units are concentrated in load pockets they can have more significant local impacts, Bowring said.

Next Meeting

Most of Wednesday’s session was taken up with introductory educational briefings from PJM’s Tom Zadlo on the two issues. The committee will hold its second meeting on the two issues December 4.

More information:

November 12, 2013

Planners Choose $1.2B PSEG Short Circuit Fix

PJM planners expect to recommend construction of a $1.2 billion double circuit 345 kV line to address a short circuit problem in the PSEG zone, ruling it less expensive than other alternatives.

The 2012 Regional Transmission Expansion Plan identified several busses where fault currents exceed 80 kA.

Planners evaluated several alternatives, including rebuilding stations to a 90 kA standard, installing current limiting reactors and installing fault current limiters.

PSEG Short Circuit Solution (Source: PJM Interconnection, LLC)

The solution chosen will isolate the Hudson 230 kV from the 138 kV at Marion and 345 kV at Farragut by converting the 138 kV buses and transmission facilities between Linden and Bergen to a double circuit 345 kV capacity.

It is projected to cost $1.2 billion but will incorporate more than $1 billion in existing baseline projects, resulting in an “avoided cost” of $160 million.

Planners rejected a recent stakeholder proposal to build parallel 700 MW HVDC converter stations. That would have cost $614 million but would not have addressed the reliability problems to be fixed by the other baseline projects.

As a result, the double circuit project “is significantly less expensive than the HVDC alternative,” PJM’s Paul McGlynn told the Transmission Expansion Advisory Committee Thursday.

An independent consultant, Burns & Roe, will validate costs and schedules and identify risk areas in the project before planners recommend it to the PJM Board of Managers.

The project, which will be constructed by PSEG, will take about four years and will require acquisition of additional underground and underwater rights of way and land acquisitions for expansion of several substations.

November 12, 2013

Pay Hike for Black Start Generators?

Payments to black start generators could increase by 27% to more than 500% under proposals scheduled to go to a stakeholder vote today.

The System Restoration Strategy Task Force will vote through Nov. 20 on up to four alternatives to the current compensation method for black start units.

An analysis presented to the task force in October showed the annual operations and maintenance compensation for a 20 MW combustion turbine would increase from the current $51,000 to more than $312,000 under NRG Energy’s market based “Proxy” formula. The PJM-Market Monitor “Modified Incentive” would boost compensation to $65,000, while Dayton Power & Light Co.’s “Minimum Incentive” would set compensation at $71,000.

While the increases could be large compared to current compensation, the overall impact on prices would be limited. Black start charges were responsible for only $0.03 of the $35.23/MWh total price of wholesale electricity in 2012 (0.1%), according to Monitoring Analytics’ State of the Market Report.

The Proxy proposal was based on a review of practices in New York and New England as well as cost figures provided by more than 50 generators that responded to PJM’s recent solicitation for black start resources. It would increase capital compensation more than six-fold and payments for fuel storage more than eight-fold.

Old Dominion Electric Cooperative (ODEC) proposed a “cost allocation” alternative that would allow increased compensation but seek to spread the costs beyond load to external generators that clear in the annual capacity auction and internal generators that neither provide black start service nor offer to do so.

“We would be willing to consider increasing compensation, but without [broader] cost allocation we remain troubled by this,” ODEC representative Steve Lieberman said at the task force’s most recent meeting last Tuesday.

Generator representatives reacted coolly to Lieberman’s request to negotiate a consensus with load-serving entities, with one calling it “worse than a zero-sum game” for generators relative to the status quo.

Black start units must be capable of starting without an outside electrical supply, maintaining frequency and voltage under varying load, and maintaining rated output for a specified time, typically 16 hours.

Proposed Changes

Black Start Annual Revenue Comparison for 20 MW CT (Source: System Restoration Strategy Task Force) — (Source: System Restoration Strategy Task Force)

The following changes are included in one or more packages to be considered by the task force:

Increasing the incentive factor — currently 10% of black start costs for units using base formula rates to determine O&M cost recovery — to the greater of 10% or $25,000.
Adding incentives based on unit availability, start times and fuel diversity.
Reducing the frequency of reviews of cost components from annual to once every five years.
Allowing compensation for NERC compliance insurance.
Allowing automatic load rejection (ALR) units to recover NERC Compliance costs as part of their variable operations and maintenance costs, as currently allowed for other black start units. ALR units can remain operating after disconnecting themselves from the grid during a disturbance.

Black Start Pool Increased

On Sept. 6, the Federal Energy Regulatory Commission approved tariff revisions that PJM said will increase the pool of potential black start generators by 64,000 MW (ER13-1911).

PJM initiated the changes over concern that it will lose much of its existing capacity by 2015 due to coal plant retirements. The RTO told FERC in its tariff filing that about 42% of its current black start capacity “may be impacted by environmental regulations.”

The changes included a broadened definition of units eligible to provide black start service and a provision allowing units in one zone to help restart generation in neighboring zones.

Revised Charter

In April, stakeholders expanded the task force’s charter to allow consideration of changes to black start cost allocation and compensation.

The Maryland Public Service Commission expressed concern with the expanded charter, telling FERC that the cost of black start service had doubled in recent years. The commission said there was a “need for cost controls given that black start service has rarely, if ever, been used.”

The task force’s expanded charter also included consideration of “back stop” options if response to PJM’s voluntary request for resources leaves gaps in coverage. However, PJM officials said last month they were pleased with the response to their recent request for additional black start resources.

PJM Executive VP Mike Kormos said the response indicated “a large pool of viable units, both proposed and existing.” Officials said it will take months to select their fleet of black start resources from among current resources and the new bidders.

November 12, 2013

PJM: Change Real-Time Pricing

PJM proposed a change in its real-time pricing mechanism, saying the current methodology is depressing energy and reserve prices.

PJM told the Market Implementation Committee Wednesday that it will propose a problem statement to consider increasing reserve requirements under certain circumstances. The revised methodology could increase reserve and real-time energy prices while reducing uplift.

Reserve requirements would be increased when operators are carrying additional resources (generation, reserves or emergency DR) to cover units at risk – for example when it is unknown whether a generator with environmental limitations will receive a waiver to continue operating.

Requirements also could be boosted when operators have data quality concerns or are uncertain about load or interchange.

PJM Load and Prices: July 18, 2013 (Source: PJM Interconnection, LLC) — An unexpected influx of imports caused prices to crash July 18 after PJM operators called on demand response.(Source: PJM Interconnection, LLC)

Because they cannot be exact in dispatching emergency demand response or scheduling generation, operators tend to err on the side of calling on more resources than are ultimately needed. PJM cited the July 18 heat wave, when an unexpected influx of imports from New York caused prices to crash after the deployment of DR.

“It’s really a matter of having the [pricing] engine recognize these actions. Right now we don’t have a mechanism to do that,” said PJM’s Angelo Marcino.

The proposal was welcomed by several stakeholders. “LMPs have been crushed for years and years and years when DR gets called,” said David Pratzon, who represents generators.

Some other members, however, said they feared that the changes could result in overly conservative actions by PJM operators, resulting in a net increase in costs rather than just a shift.

“I would hate to see reserve requirement creep,” said David “Scarp” Scarpignato, of retail marketer Direct Energy.

“We risk over-responding,” agreed one load-serving representative.

Barry Trayers, of Citigroup Energy, said the changes could increase uncertainty. “It’s going to make it even harder for stakeholders to ascertain where we are in the world of scarcity.”

One representative said PJM also should work to incorporate intraday changes in natural gas costs. But Pratzon said PJM should act promptly on this issue and defer a wider-ranging discussion until later. “People are already making arrangements for buying and selling energy” for next summer, Pratzon said.

Market Monitor Joe Bowring said he supports PJM’s efforts but added: “The mechanics of what PJM is planning need to be made substantially more clear.”

November 12, 2013

AP South, Cleveland Draw Congestion Relief Proposals

AP South and the Cleveland interface attracted the most attention in PJM’s inaugural window for proposed market efficiency upgrades.

PJM staff provided the Transmission Expansion Advisory Committee last week with a summary of 17 proposals ranging from $200,000 to $64 million.

Merchant developer LS Power was the most ambitious, proposing four projects totaling $181 million in eight zones. Transource (American Electric Power and Great Plains Energy) was second, proposing three projects in the AEP and ATSI zones totaling $135.5 million.

The three incumbent utilities that took part — Commonwealth Edison, Dominion Virginia Power and FirstEnergy — all stayed at home, with proposals in their own transmission zones. Duke (with partner American Transmission Co.) did the same, proposing one project in the Duke Ohio-Kentucky zone.

AP South

AP South attracted seven congestion relief proposals.

Transource proposed two alternatives to address congestion at AP South and the AEP-Dominion interface. The cheaper option features a 500 kV substation with series capacitors at a cost of $39.3 million. A second builds on the first with additional series compensation at an extra $24 million.

Dominion proposed three projects incorporating Thyrister-controlled series capacitors at costs ranging from $20.1 million to $24.6 million (total cost $69.4 million).

FirstEnergy and LS Power made pitches for AP South and the Hunterstown 230/115 kV line with projects of $54.3 million and $61.7 million, respectively.

Separately, LS Power proposed a new Hunterstown-Cumberland 230 kV line and substation improvements for $63.9 million. FirstEnergy proposed spending $8 million to add a 230/115 kV transformer and reconductor the Hunterstown-Oxford 115 kV line.

Cleveland Interface

Projected Annual Conjestion Costs (Source: PJM Interconnection, LLC) — (Source: PJM Interconnection, LLC)

FirstEnergy, LS Power and Transource each proposed projects to relieve congestion at the Cleveland Interface.

The most expensive is FirstEnergy’s $61.7 million proposal to improve a 138 kV substation in the ATSI zone.

LS Power’s $44.9 million project, which includes the ATSI and PENELEC zones, would add a new Erie West–Ashtabula 345 kV line and a 345/138 kV transformer.

Transource offered the least costly project, a new 138 kV substation in the ATSI zone at a cost of $32.9 million.

Next Steps

PJM’s request for congestion relief proposals was its first under Order 1000, in which the Federal Energy Regulatory Commission sought to increase competition by largely eliminating utilities’ monopoly over transmission development in their territories.

Proposals must clear a minimum 1.25 benefit-to-cost threshold to be considered by the Board of Managers for inclusion in the Regional Transmission Expansion Plan. PJM staff will review the projects through January and make recommendations to the Board in February.

PJM will conduct independent cost reviews on projects exceeding $50 million and on those below $50 million that have tight benefit-cost margins, said PJM’s Paul McGlynn.

November 12, 2013

Summer 2013 Load Growth Fastest Since Recession

PJM’s weather normalized summer peak increased 950 MW in 2013, the largest increase since load growth resumed after the recession.

The 0.6% increase over 2012 is “no great shakes but moving in the right direction,” PJM’s John Reynolds told the Planning Committee during a briefing last week.

The peak was 0.2% (368 MW) below PJM’s forecast. “It’s been a challenging time for us for load forecasting since the recession,” said Steve Herling, vice president of planning. “The primary input is econometrics — over which we have no control.”

Peak diversity for 2013 as 0.3%, much lower than the forecasted 4.3%, as a result of the single RTO-wide heat wave July 15-19.

It was the first summer that the top five coincident peaks have come in the same calendar week since PJM started collecting the data. “The entire story of the summer of 2013 can be told in one week in the middle of July,” Reynolds said.