Page 1456 – RTO Insider

November 10, 2015

PJM Operating Committee Briefs

VALLEY FORGE, Pa. — A military blimp that broke free from the Aberdeen Proving Ground in Maryland on Oct. 28 and dragged a steel tether some 125 miles before deflating in Montour County, Pa., caused surprisingly little damage to power lines, PJM’s Chris Pilong told the Operating Committee last week.

pjm — US Military aerostat blimp (Source: Defense Department)

“We actually didn’t see any impact until it got to PPL territory,” he said.

There, around 2 p.m., it knocked out one 500-kV line, and the two 230-kV lines, in the Sunbury-Susquehanna and Montour area.

In addition, three 69-kV sub-transmission lines were felled by the runaway airship’s several-thousand-foot-long tether, causing a blackout for as many as 35,000 customers.

“Despite the odd cause … there was no permanent, lasting damage,” he said. “Just an unusual afternoon.”

William Skumanich of PPL said those in the company’s control room at the time were flummoxed.

“We in the control center did not know what was going on, and all of a sudden we get this string of outages,” he said. “It was really a mystery. We really thought it was a tornado.”

PPL spokesman Paul Wirth said power was restored to affected customers by midnight, and all damage was repaired later the next day.

ComEd Open-Loop Interface Created

PJM has introduced a change to the ComEd reactive transfer interface. The closed-loop interface, implemented in June 2013, is composed of all ComEd tie lines and is used to control reactive issues during summer peaks, when the zone is importing power.

The interface is being changed to an open loop of six of the ComEd extra-high voltage lines on the zone’s eastern border. Dubbed CE-EAST, it will go into effect March 1.

The change is being made so that certain generators in MISO can help with voltage issues in the Chicago area.

Operational impact will be minimal, PJM said, and the change will be reflected in Manuals 03 and 37.

Winter Reserve Target Same as Last Year

The committee endorsed a 27% winter reserve target, the same value as last year.

The target is based on unit summer ratings and expressed as a percentage of the forecasted weekly peak load. It is derived from simulations of the 13-week winter period.

PJM operations will seek to maintain the 27% margin in scheduling generator maintenance outages.

Concept of ‘Soak Time’ Parameter Introduced

PJM initiated discussion with stakeholders over a proposed new parameter for Capacity Performance units called “soak time,” with the goal of having a concept in place by June 1.

PJM’s Tom Hauske introduced the proposed definition as “the minimum number of hours a unit must run, in real-time operations, from the time the unit is put online (breaker closure) to the time the unit is at its economic minimum or dispatchable.”

Units with a soak time greater than their minimum run time would be able to petition for a unit specific parameter adjustment.

Committee Chair Mike Bryson said the concept primarily would apply to fossil-fired steam units and would not affect penalty assessment hours under the new Capacity Performance product.

ComEd SPS Changes in the Works

Alan Engelmann of Commonwealth Edison gave the following updates regarding special protection systems (SPS):

Byron Unit: A new 345-kV line between Station 6 Byron and TSS 144 Wayne, expected to be in service by June 2017, will resolve the stability issues for which the Byron SPS was designed. On completion of the line, the Byron Unit Stability Trip Scheme will be removed. As part of the project, a new breaker was installed in October.
Powerton 345-kV bus and Powerton Unit: In a project targeted for completion in 2017, a reconfiguration of the Powerton 345-kV bus and breaker replacements will allow the removal of the Powerton SPS when the station is in normal configuration.
Northbrook/Highland Park Transfer Trip: This SPS prevents thermal overloads and low voltage. A normally closed bus tie line will be installed at Highland Park by December, and the SPS no longer will be needed.

— Suzanne Herel

November 10, 2015

PJM Planning Committee TEAC Briefs

VALLEY FORGE, Pa. — The Planning Committee last week endorsed comprehensive revisions to Manual 19 to incorporate changes to the load forecast model.

The changes account for trends in equipment and appliance saturation and energy efficiency; revise weather variables; update weather station assignments to zones; and modify the weather normalization procedure.

Members decided to remove a change that would have added distributed solar generation to the model this year, saying they wanted to see more data on its predicted effect first.

PJM’s John Reynolds said that in response to requests for more information about how the new load model was developed, PJM will be producing a white paper on the subject early next year.

Steve Herling, PJM vice president for planning, encouraged the group to approve the changes, carving out the solar section, instead of holding them up.

“Our concern obviously is that we don’t want to get behind the curve, which we did to a degree with energy efficiency,” he said.

Panel Re-examining Reserve Requirement Study

The Resource Adequacy Analysis Subcommittee will be holding two education sessions as part of its effort to re-examine all modeling assumptions for the 2016 Reserve Requirement Study.

The first is scheduled for 1 to 4 p.m. on Nov. 24. The second is 9:30 a.m. to 12:30 p.m. on Dec. 9. Both will be held in person at the Valley Forge campus and via WebEx.

The subcommittee will schedule meetings as needed through the first quarter of next year in order to finalize RRS assumptions and bring them to the committee for endorsement in April.

PJM’s Tom Falin said it is the first re-evaluation of the process in about seven years. Planners are focusing on the full study to underscore that the installed reserve margin “is not the most important output from the study,” Falin said. Members had questioned the recent increase in the IRM, saying it seemed counterintuitive under the new Capacity Performance model. (See “IRM, FPR Rising; PJM Methodology Challenged” in PJM Planning Committee Briefs.)

Falin said the RAAS discussion will focus on three drivers: the selection of PJM and world load models, the development of capacity models and the representation of the world area. It also will consider the impact of CP on RRS assumptions.

Two More Units Headed for Deactivation

Two generating units have applied for deactivation in January.

Perryman Unit 2, a 51-MW facility in the BGE transmission zone, will be deactivated Jan. 1.

Interim operating measures have been identified until a baseline upgrade is completed there by June 2017. That upgrade, a new 115-kV switching station, is expected to cost $26 million, the cost of which is being designated to Baltimore Gas and Electric.

The second unit to be decommissioned is the 2-MW Pottstown landfill, in the PECO transmission zone. Landfill owner Waste Management said that flows of landfill gas have declined significantly since the landfill was closed in 2005 and that there is no longer enough gas to drive the turbine. It will be deactivated Jan. 15. No reliability impacts have been identified by the closure.

— Suzanne Herel

November 10, 2015

PJM Market Implementation Committee Briefs

VALLEY FORGE, Pa. — The Market Implementation Committee last week unanimously approved a problem statement to consider revisions to the parameter limited schedule (PLS) exemption process.

Bob O’Connell, who presented the issue on behalf of PPGI Fund A/B Development, said Tariff changes made in 2012 have made it more difficult to obtain exceptions to default PLS values, limitations imposed on generators’ minimum run times or other elements of cost-based offers.

O’Connell took issue with the “inflexible deadline” for long-term exceptions, which, he said, “does not recognize various changes that may take place on the market participant’s side that may result in the need to get around the Feb. 28 deadline.”

For example, he said, he has clients currently testing units that might not be ready by Feb. 28. “They don’t know if they should apply for anything,” he said.

There also are challenges with the resolution that has been proposed, he said, which is to seek a waiver from FERC. First, there is no guarantee the commission will rule, he said.

“Second, if a market participant is seeking an exception, right now the market participant works with the Market Monitor and PJM to determine whether, one, the exception is merited and, two, what the numbers should be,” he said. Once FERC is approached, he said, “Everybody can be involved, even if they don’t have the information.”

“What we’re seeking to do is start up the stakeholder process to rethink what’s on the table right now and come up with something that provides an administratively efficient process.”

Debate Continues over Confidentiality of Information

The committee continued to debate allowing PJM to make public certain types of data, such as uplift payments, demand response deployments, generator outages and cleared capacity resources. The changes would modify Manual 33: Administrative Services. (See PJM Stakeholders to Study Relaxing Confidentiality Rules.)

Jim Benchek of FirstEnergy said his company is most concerned with two of the six categories: details about individual generation outages and cleared capacity resources.

Regarding the outages, he said, “As a resource owner, we believe that is our data, and we really don’t want to release it to make it public.”

If PJM, the market seller and the Independent Market Monitor agree the information is not confidential, he said, “then it would be OK to release that data.”

In addition, he said, outages carry a variety of implications, including Capacity Performance penalties, and information about them might lead some to speculate about the health of a company. Likewise, releasing information about cleared capacity resources provides a window into a company’s position in the market, he said.

A number of suppliers echoed his concerns.

Monitor Joe Bowring said he had concerns about proposed changes to the capacity resource section of the manual, which would allow PJM to release the identities of resources that clear the third Incremental Auction.

“We don’t think supply curves in the capacity market should be made public,” Bowring said. “The information is very persistent from year to year. It supports collusion.”

Compromise Offered on Masking FTR Ownership

DC Energy’s Bruce Bleiweis, who has been leading a rocky effort to mask the ownership of financial transmission rights, said he was willing to offer a compromise: that they be kept private for 90 days.

At a September meeting of the MIC, Bleiweis garnered only 61% approval of his problem statement — an indication that he may have trouble winning the two-thirds majority needed for a rule change. (See “PJM to Consider Masking FTR Ownership” in PJM Market Implementation Briefs.)

At that meeting, Bleiweis had asked PJM to look into whether it discloses the ownership of its other market products. PJM’s Tim Horger confirmed last week that the RTO does not.

“In other types of markets, participant info is not posted out there,” Horger said. “PJM can support a change for removing it, but [we] want what the stakeholders want. We don’t have a strong interest one way or the other.”

Bowring reiterated his support for the status quo.

“We think the current release of ownership information makes sense, and we don’t see a reason for your additional compromise proposal,” he said.

Bleiweis said FTR owners should be able to expect the same treatment as other market participants.

“We’re not looking for less transparency; we’re looking for consistency,” he said.

“Our biggest concern is there are instances where you have multi rounds of auctions, and we were hoping that the membership, the Market Monitor and PJM would agree that releasing that information intraround — so that you see the ownership after round one, before round two — that you shouldn’t reveal that kind of confidential information.”

— Suzanne Herel

November 9, 2015

Energy Department OKs Canadian Hydro Line in New England

By William Opalka

The Department of Energy on Thursday issued the final environmental impact statement for the New England Clean Power Link, recommending approval of a presidential permit for the cross-border project, which would transmit 1,000 MW of Canadian hydropower into New England.

The 154-mile, $1.2 billion HVDC project was proposed in early 2014. The final report includes changes made in response to comments on the department’s draft EIS in June. (See Lake Champlain Cable into New England Progresses.)

Among the changes were updated technical information; alternatives included in the U.S. Army Corp of Engineers 404 permit; additions to water resource analyses requested by the Environmental Protection Agency; and details on the project construction period and impacts on the long-eared bat and wetlands.

The merchant line, which would be entirely underwater or underground, is still undergoing permitting review by Vermont.

Transmission Developers Inc. New England, a unit of The Blackstone Group, anticipates that all major federal and state permits will be granted by the end of the year and the project would be in service in 2019. Ninety-eight miles of the cable would be buried under Lake Champlain, and most of its land-based route would be underground to Ludlow, Vt.

TD-NE began an open solicitation on Oct. 15 for customers to buy capacity on the line, with expressions of interest due by Dec. 4.

“We are confident that, once built, the New England Clean Power Link will deliver environmental and economic benefits to the people of Vermont and New England and do so in a way that minimizes impacts to communities and helps meet the region’s growing energy and environmental challenges,” TDI-NE CEO Donald Jessome said in a statement.

The Northern Pass line, which would deliver 1,090 MW to New England from Canada, has an agreement between its U.S. sponsor, Eversource Energy, and Hydro-Quebec. That $1.6 billion project has generated much more controversy because most of it is above ground. It also is not as far along in the regulatory process as the Clean Power Link. (See Northern Pass Files for Siting Approval, Revises Cost.)

November 9, 2015

FERC Finds ‘No Significant Impact’ from NE Pipeline Expansion

By William Opalka

FERC staff has concluded that a 13.5-mile natural gas pipeline expansion to serve increased demand in Connecticut will have “no significant” environmental impact.

The Connecticut Expansion Project, proposed in July 2014 by Tennessee Gas Pipeline, will provide an additional 72.1 million cubic feet per day of firm transportation service to three shippers: Connecticut Natural Gas, Southern Connecticut Gas and Yankee Gas Services.

Public comments on FERC’s environmental assessment of the project are due Nov. 23 (CP14-529).

Tennessee Gas said that gas delivered into its system has increased by 32% over the past four years, with lines serving the state nearing capacity. “Tennessee states that it is only through the expansion of its existing infrastructure that it would be able to deliver the incremental volumes requested by the project shippers in binding precedent agreements, while maintaining service to existing shippers and pressure profiles necessary for system operations,” FERC’s report states.

The demand is being driven by increased gas use in electric generation and heating. The 2013 Connecticut Comprehensive Energy Strategy proposed the addition of 300,000 natural gas heating customers among homes and businesses, most of them switching from fuel oil.

The environmental assessment rejected allegations that Tennessee Gas attempted to reduce the level of environmental scrutiny by improperly separating the Connecticut project from the Northeast Energy Direct Project, which is intended to increase supply throughout New England. (See New England Governors Revise Energy Strategy.)

“The proposed project would function independently from the NED Project,” staff wrote. “… The projects have different purposes [and] different start and end points.”

The Connecticut project, which will predominately use existing rights-of-way, includes:

4 miles of new 36-inch-diameter pipeline loop near the Town of Bethlehem, in Albany County, N.Y.;
8 miles of 36-inch-diameter pipeline loop near the Town of Sandisfield, in Berkshire County, Mass.; and
3 miles of 24-inch-diameter pipeline loop near the Town of Agawam, in Hampden County, Mass., and the Towns of Suffield and East Granby in Hartford County, Conn.

The project also includes modifications to a compressor station in Massachusetts and other facility improvements.

Construction could start this year if approvals are granted, with an in-service date of Nov. 1, 2016, Tennessee Gas said.

November 9, 2015

Algonquin Submits Pre-Filing Request for Access Northeast Pipeline

By William Opalka

The developer of a multistate pipeline project to move natural gas from the Marcellus shale region through New England asked FERC on Tuesday to start a process to expedite its formal application.

Spectra Energy’s Algonquin Gas Transmission asked FERC to grant permission for the pre-filing review on the proposed Access Northeast project by Nov. 13 (PF16-1).

The company expects to file a formal application in about a year and hopes to put the first phase of the project in service by November 2018.

“Algonquin is seeking authorization to use the pre-filing review process to provide the necessary environmental information to commission staff for review at the earliest practicable time in order to expedite the processing of Algonquin’s certificate application,” the filing states.

Developers say the $3 billion Access Northeast project will allow direct pipeline interconnections for 60% of ISO-NE’s gas-fired power plants. Proponents say that will save the region’s ratepayers $1 billion annually in lower electricity costs.

Access Northeast will have capacity to deliver up to 925,000 dekatherms/day, enough to supply 5,000 MW of generation, the company says. Algonquin says more than 95% of Access Northeast will use existing pipeline and utility rights of way.

The line will be able to accommodate new power plants being sited on Algonquin, or nearly 2,750 MW of additional generation that has been publicly announced or cleared the ISO-NE capacity auctions, according to the company.

The project is being developed by a consortium of Spectra Algonquin Holdings, Eversource Energy and National Grid. In addition, Central Maine Power submitted a bid to secure firm transportation service during the pipeline’s open season earlier this year.

“Access Northeast will provide true ‘last mile’ supply access for 5,000 MW of generation from the approximately 12,000 MW of gas-fired generation currently attached — or expected to be attached over the next five years — to Algonquin and Maritimes & Northeast pipeline systems,” Bill Yardley, Spectra Energy Partners’ president of U.S. transmission and storage, said in a statement. “That is firm capacity directly to the generator during the coldest days. Without the last mile capacity, New England’s electric reliability concerns related to gas power plants will remain unresolved.”

Pipeline plans have generated controversy as some state regulators have endorsed a regional plan to have funding come from electricity customers. (See Massachusetts Regulators Endorse Pipeline Contracts.)

November 9, 2015

FERC Again Dismisses Challenge to 2014 ISO-NE Capacity Auction

FERC has again denied a rehearing request by Public Citizen over the results of ISO-NE’s eighth Forward Capacity Auction (EL14-99, ER15-117).

The consumer group had challenged a previous order that accepted the results for the 2017/18 capacity commitment period, arguing that capacity from the Brayton Point facility in Massachusetts had been withheld to drive up prices. In accepting the results of the February 2014 auction and dismissing the Public Citizen challenge last December, FERC opened a section 206 proceeding on the appropriate treatment of imports and establishing review and mitigation procedures for import capacity. (See FERC OKs Tightened ISO-NE Screening on Capacity Imports.)

FERC said in its Oct. 28 order that Public Citizen inappropriately tried to expand the import capacity proceeding with an unrelated matter. “The commission previously stated that there was no evidence that the owners of Brayton Point engaged in any inappropriate behavior in FCA 8, and Public Citizen has provided no argument or evidence that causes us to reconsider this finding,” it wrote.

The commission accepted Tariff revisions filed by the RTO intended to address FERC’s concern that future auctions with small surpluses might not protect customers against the exercise of market power by import resources.

— William Opalka

November 9, 2015

Ahead of Most, Northeast Still Faces Clean Energy Challenges

By William Opalka

BOSTON — The Northeast may be further along than most regions in meeting the Environmental Protection Agency’s new carbon emission rules, but it also faces challenges, speakers at Infocast’s 2nd Annual Northeast Energy Summit agreed. About 60 people attended the conference Oct. 27-28.

As part of the Regional Greenhouse Gas Initiative, New York and the New England states are already doing much of what EPA’s Clean Power Plan requires.

Although the region will need to add electric transmission and gas pipelines to serve the change from coal to gas that’s already occurred, “I don’t see a big change resulting from the Clean Power Plan against business as usual,” said Ann Weeks, legal director for the Clean Air Task Force. She predicted New England will be a net exporter of carbon allowances under the EPA rule. (See Northeast on Way to Compliance with Clean Power Plan.)

But the region’s public policies and energy markets aren’t always aligned, said others.

While the region has long supported renewables, the closure of two nuclear plants adds more pressure to further develop clean and cost-effective resources, said Jon Norman, vice president of commercial development for Brookfield Renewable Energy, a Canadian firm that primarily owns hydropower resources. Entergy recently announced it will close both its Pilgrim nuclear plant in Massachusetts and its FitzPatrick plant in New York.

“We need to continue to push that ball forward in the wake of losing that non-emitting generation,” Norman said.

“The Northeastern markets for investors in renewable generation are not on the whole a very friendly environment, compared to others,” added James Guidera, North America managing director of energy and infrastructure for Credit Agricole.

Wind developers in the Midwest and West have benefited from the certainty of long-term power purchase agreements that have “a dramatic impact on promoting projects,” he said.

With cheap natural gas increasingly setting marginal prices, energy markets in the Northeast “do not really recover the cost of renewable energy,” he added. Renewable portfolio standards, meanwhile, provide “subsidies that don’t provide enough [money] to encourage investment.”

One attempt to address New England’s challenges is a multi-state clean energy procurement process, which seeks to bring economic scale to projects that might not be viable for individual states. (See New England States Combine on Clean Energy Procurement.)

“We now know with experience in New England that without long-term contracts, even the renewable portfolio standard and the volatile spot market for renewable energy credits is not sufficient to make those investments happen,” said Judy Chang, principal at The Brattle Group.

But that does risk sustainable development of the clean energy market, she cautioned. “We don’t want everything under long-term contract because that takes away price signals for the investment community.”

Regional or statewide policy mandates also can run headlong into local concerns, said Michael Voltz, director of energy efficiency and renewables for PSEG Long Island, which runs the power system for the publicly owned Long Island Power Authority.

Next year, PSEG Long Island will develop an integrated resource plan, which will require it to balance the constituencies of clean energy proponents, who would like more solar and wind power, against those of consumer advocates, who may prefer cheaper new natural gas generators.

“The other constituency is the local school district or tax body because there are town and school officials receiving fairly significant tax revenue from old antiquated natural-gas fired power plants that we don’t feel we need anymore,” Voltz said. “But shutting them down is not an easy thing to do politically.”

Also Heard at the Northeast Energy Summit:

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November 8, 2015

RTOs: ‘A Form Between Government and Business’

What is an RTO?

In a 2007 article in the Energy Law Journal, Michael H. Dworkin and Rachel Aslin Goldwasser gave perhaps the definitive answer, describing RTOs as “larger than states but smaller than nations, [taking] a form that is between government and business, thus creating serious accountability problems.”

“Unlike governments, which must answer either directly to the electorate or to the people’s representatives, RTOs are not subject to elections or legislative confirmation processes,” they noted.

Their article suggests RTOs can be viewed through several lenses, “as agents of the FERC, as monopolists or private regulated entities, as ‘hybrid’ organizations, as similar to commodities trading markets, as agents of some of the market participants, and as planning processes.”

“Because confidence in the RTOs is vital to their success, stakeholders and members of the public needed to see them as independent actors dedicated to the public interest,” they write.

FERC gave much thought to the nature of RTOs in the rulemaking that led to Order 2000, which set minimum requirements for the organizations. FERC was concerned, they write, that “the potential for undue discrimination increases in a competitive environment unless the market can be made structurally efficient and transparent with respect to information and equitable in its treatment of competing participants.”

In the order, FERC noted that industrial consumers (the Electricity Consumers Resource Council, the American Iron & Steel Institute and the Chemical Manufacturers Association) had argued “that market participants must perform monitoring and, accordingly, an RTO’s operations should be fully transparent.”

The America Public Power Association told FERC in the rulemaking that the grid operators “still represent the interests of the transmission owners that formed” them. APPA said FERC should view RTOs as “regional monopolies that it must vigorously regulate, not regional extensions of the commission itself.”

Since the order, the authors noted, “there has been a chorus of questions regarding RTOs, their efficacy and their governance,” including reports by APPA and PJM stakeholders that argued that RTOs were not sufficiently accountable.

“The Energy Consumers Resource Council, a consortium of large industrial users, also produced a white paper questioning the ability of current RTO structures to provide real market solutions and claimed that ‘governing structures of the organized markets are skewed to benefit suppliers.’

“It is important to note,” the authors added, “that many of these ‘large consumer’ groups were originally supportive of restructuring and the RTOs.”

Dworkin, former chairman of the Vermont Public Service Board, is a professor and director of the Institute for Energy and the Environment at Vermont Law School.

Dworkin said yesterday that FERC “delegates great discretion to RTOs; and the RTOs’ exercise of that discretion is heavily influenced by the meetings of its stakeholders… The system would be far healthier if the people and businesses that will be affected can learn what was and wasn’t said about the issues that may well affect them.”

Goldwasser, a Vermont Law graduate, was a law clerk to a U.S. District Court judge in Maine when she co-authored the article. She is now executive director at the New England Conference of Public Utilities Commissioners (NECPUC). She declined to comment.

— Rich Heidorn Jr.

November 8, 2015

ERCOT Confirms Resource Adequacy for Winter

By Tom Kleckner

ERCOT released its final winter assessment Nov. 2, indicating it has more than sufficient generation to meet an anticipated peak demand of 57,400 MW. The Texas grid operator says it has more than 79,000 MW of generation resources available.

ERCOT’s final winter Seasonal Assessment of Resource Adequacy (SARA) focused on expected reliability scenarios for December through February. It reflects forecasted expectations based on customer demand experienced during recent cold-weather events and current expectations for average weather this winter.

Warren Lasher, ERCOT’s director of system planning, said the grid expects to meet winter demand “across a broad range of operating conditions and weather scenarios … even during high-load conditions with extreme generation outages.”

ERCOT’s senior meteorologist, Chris Coleman, told reporters during a conference call that he is forecasting wetter-than-normal conditions for December and January, based on an El Niño winter pattern that “has an opportunity to be the largest on record.” In Texas, he said, that will result in cloudy weather, leading to milder overnight temperatures and morning lows.

“If, as expected, El Niño backs off in intensity by February,” Coleman said, “we could see a late-season cold pattern that drives temperatures lower across the ERCOT region.”

In February 2011, severe cold weather and unexpected plant outages forced ERCOT to call for rolling blackouts. While the grid’s reserve margin has increased since then, ERCOT has also taken other steps to minimize a repeat occurrence.

“We’re more prepared for winter-weather issues than we have been in the past,” said ERCOT spokesperson Robbie Searcy. “We’ve been spending more time on site visits and working with generation owners on their winter plans.”

The grid has also added nearly 1,100 MW of resource capacity from mostly wind projects since its preliminary winter SARA, issued in September. (See ERCOT Expects Sufficient Generation for Fall, Winter.) It said several units previously in seasonal-mothball status have returned to service and several new resources have become operational.

ERCOT last week also released its preliminary SARA for next spring, based on average springtime weather conditions over the past 13 years. The study’s results indicate the grid will also have sufficient installed capacity to meet forecasted peak demands during March-May 2016.

The grid operator estimates 1 MW of demand is typically enough to power about 500 homes during mild weather conditions and about 200 homes during summer peak demand.