Integrating offshore wind into PJM will require billions in new transmission spending, either with radial lines from wind farms to shore or something like the Atlantic Wind Connection, a proposed a 300-mile transmission “backbone” off the coast from New Jersey to Virginia. Lines on shore also will have to be upgraded or built.
What projects will be built, and how much they will cost, will depend on how much generation is added and where it is brought onshore.
PJM has conducted studies of offshore wind in its last three annual Regional Transmission Expansion Plans (RTEP). The studies looked at integrating various amounts of offshore wind in addition to its current 18,000 MW of nameplate onshore wind.
(Source: Atlantic Wind Connection)” width=”300″ height=”253″ /> The Atlantic Wind Connection would link wind farms along New Jersey, Delaware, Maryland and Virginia using undersea cables.(Source: Atlantic Wind Connection)
Among the potential projects are the Atlantic Wind Connection, which backers say could circumvent transmission congestion in New Jersey on hours when wind power is not generated.
In addition, a study released in January found that injecting up to 10,000 MW of wind in Virginia and North Carolina would require $1 to $2 billion in transmission upgrades.
2010 Conceptual Study
The 2010 RTEP included a “conceptual” study on the impact of importing 10 GW, 20 GW and 30 GW of wind off the Delaware, Maryland and New Jersey coasts. Equal amounts were modeled at four injection points in New Jersey, on the Delmarva Peninsula and in Virginia.
The study found that 10 GW both “unloaded” higher cost generation and increased generation east of PJM’s major west-to-east constraints, resulting in a 5.5% load payment decrease compared to the base scenario with no offshore wind.
Doubling wind to 20 GW increased load payment savings to only 7.5%, as the added volume caused constraints near offshore injection points that limited deliverability. Boosting generation to 30 GW produced virtually the same results as the 20 GW scenario.
2011 RPS Scenario Study
In 2011, the Organization of PJM States (OPSI) asked PJM to study how the system would respond if all states met their Renewable Portfolio Standards (RPS) with land based and offshore resources within the RTO.
One scenario that assumed 4 GW of offshore wind found that high levels of Midwest onshore wind would cause heavy congestion in western PJM, with 19 thermal overloads, most on 345-kV lines. Increasing offshore wind to 20 GW caused congestion in Eastern MAAC, with 53 violations, all but four of them on 230-kV lines.
PJM planners modeled two transmission overlays that solved the reliability violations and improved wind deliverability. The overlays allowed each state to meet their RPS goals – albeit not solely with in-state resources. Thus wind-poor states would need to obtain rights to renewables from states with excess wind.
The overlays reduced congestion costs to $6.6 billion (from $8.8 billion) in the 4 GW scenario and to $6.7 billion (from $7.4 billion) in the 20GW scenario. That compares with $5 billion in congestion under the base case without overlays or offshore wind. The analysis did not estimate the cost of the overlays.
2012 RPS Scenario Study
The recently-released 2012 RTEP furthered the RPS analysis, this time including energy deliveries from outside PJM. The 2012 study also included a request from Maryland and Delaware to examine the reliability and cost impacts of new transmission to deliver offshore wind such as the Atlantic Wind Connection (AWC).
Three scenarios were developed using a 2027 starting point base case. Two of scenarios assumed 36 GW of nameplate wind capacity and 7 GW of solar capacity would be available within PJM to meet state targets. The third scenario assumed 21 GW of wind and 7 GW of solar capacity within PJM, with 40 percent of remaining state RPS targets satisfied by wind imported from outside the RTO.
The study found onshore wind from the west faced transmission limits, primarily on 345 kV lines and above, while offshore wind was primarily constrained by 230 kV and above transmission. The study used PJM’s generator deliverability test to identify flowgates limiting deliverability at peak demand. PJM also identified conditions under which wind might be curtailed during light loads.
North Carolina Wind Integration Study
North Carolina – PJM Offshore Wind Study: Injection Points Map (Source: NCTPC-PJM Joint Interregional Reliability Study, January 2013)
In January, PJM released the results of a study that estimated injecting up to 10,000 MW of wind at a substation in southeast Virginia and two substations in North Carolina would require $1 to $2 billion in transmission upgrades. The study was done jointly with the North Carolina Transmission Planning Collaborative (NCTPC), which includes the Progress Energy Carolinas (PEC) and Duke Energy Carolinas (DEC) balancing areas.
It looked at how the systems would perform at off-peak load conditions when wind is typically strongest.
The study looked at injections of:
1,000, 2,000 MW and 4,500 MW at PJM’s Landstown 230 kV substation;
1,000 MW to 3,500 MW at PEC’s Morehead City 230 kV substation area; and
1,000 MW to 2,000 MW in PEC’s Southport 230 kV substation area.
It found that Landstown could accept up to 2,000 MW without major upgrades but that imports of more than 4,500 MW would require a new 500 kV substation in addition to upgrades to the 500 kV 230 kV network.
Progress Energy Carolina’s injection points required upgrades in all scenarios.
Although as much as 6,000 MW of the power would sink in PJM, no more than $349 million of the transmission improvements would be within the RTO’s footprint.
It’s unclear how the cost would be allocated under FERC’s new Order 1000 rules, but PJM loads seen as benefiting would likely have to assume a share of the North Carolina cost to get the transmission built.
It isn’t only PJM’s Atlantic states that see promise in offshore wind. The Great Lakes also offer strong winds, along with their own unique challenges — winter ice, opposition from tourist towns, and in Pennsylvania, development restrictions put into law by casino opponents.
Michigan, Ohio, Illinois, Pennsylvania and Indiana have potential Great Lakes wind generation of 2 million GWh annually, three times their electric consumption, according to the National Renewable Energy Laboratory (NREL). Of the total potential of 487 GW about one-third are in depths of 30 meters or less. (These “technical potential” estimates generally don’t consider economic or market constraints that will reduce actual renewable generation.)
Michigan, with shorelines on three lakes, has the largest share of potential lake wind, although Ohio benefits from its 312-mile shoreline on the shallowest, Lake Erie. Portions of Lake Ontario (New York) also have shallow depths. The other lakes are mostly deep water, which would make wind development more expensive.
False Starts in Michigan, Pennsylvania
Great Lakes and Atlantic Ocean Wind Speeds Map (Source: National Renewable Energy Laboratory)
In 2012, 10 federal agencies and the states of Illinois, Michigan, Minnesota, New York and Pennsylvania signed a memorandum of understanding to coordinate and simplify regulatory review of offshore wind projects. While the states own the lake bottoms, federal law requires approval of the U.S. Army Corps of Engineers for the placement of fill or structures, including electric transmission lines, in or under navigable waters.
The Corps will make its decisions in coordination with the other federal agencies after considering impacts on migratory birds and bats, impacts on air traffic and radar capabilities and potential shipping disruptions.
Despite the Lakes’ great potential, would-be developers have been stymied to date by inconsistent state government support and aesthetic concerns from lakeshore towns.
Michigan jumped into the offshore race in 2009 when Gov. Jennifer Granholm, a Democrat, formed the Michigan Great Lakes Wind Council. The council issued a 2010 report identifying five optimal areas for wind development: one in Lake Superior and two each in Michigan and Huron.
Offshore wind also seemed to be gaining traction with officials in Wisconsin, Ohio and Illinois. Then the 2010 elections, which replaced Democratic governors with Republican ones in Michigan, Wisconsin and Ohio, changed the dynamic. “It was like somebody flipped the switch and the resounding collective interest in wind energy on the Great Lakes disappeared overnight,” Arnold Boezaart, director of the Michigan Alternative and Renewable Energy Center at Grand Valley State University, told Midwest Energy News.
In 2011, the New York Power Authority abandoned a proposed 150 MW Great Lakes wind project, saying it “would not be fiscally prudent” at costs two to four times more than onshore wind. The same year, Ontario ordered a moratorium on offshore wind development to conduct additional studies. Two years and three studies later, the moratorium continues.
Ohio: Cleveland in the Lead
Ohio has the clear lead to be the site of the first freshwater wind in North America — though even there it’s far from certain that it will happen.
The Lake Erie Energy Development Corp. (LEEDCo), a non-profit economic development organization, is planning a six-turbine, 18-MW pilot project in Lake Erie, seven miles offshore Cleveland. It was one of seven offshore projects that won $4 million grants from the Department of Energy in February to complete engineering, site evaluation, and planning.
Developers recently conducted soil sampling to determine how to build the foundations for the $150 million “Icebreaker” project. The developers need to complete their plans and obtain permits by February 2014 to be eligible for an additional $50 million grant from DOE.
LEEDCo, founded in 2009 by the city of Cleveland and four lakeside counties, has set a 2015 target for operation. “We will certainly be the first freshwater project,” said LEEDCo spokesman Eric Ritter.
LEEDCo has a memorandum of understanding to sell 25% of the farm’s output to Cleveland Public Power.
It is hoping to encourage other utilities and retail marketers to purchase the remaining output by getting 10,000 retail consumers to sign a “Power Pledge” indicating their willingness to pay extra for offshore wind. To date, almost 1,000 consumers have signed the pledges, which allow them to specify how much they are willing to see their electric bills increase. The median increase volunteered was $10 per month.
Ritter said the pledge is intended to counter the notion “that people aren’t willing to pay extra for (renewable) electricity.
Michigan: Developer “Run Out of Town”
Scandia, a Norwegian company, ran into a buzz saw in the tourist town of Ludington in 2009 after announcing plans for a 200-turbine wind farm in Lake Michigan. Residents were concerned the wind farm would ruin their lake views and hurt local tourism. “They were basically run out of town,” Boezaart told Midwest Energy News.
Michigan Gov. Granholm was replaced in 2010 by Republican Rick Snyder, who says that offshore wind is “not a priority.”
Last month, two Michigan state representatives introduced a bill that would stop any research or production of offshore wind power in the Great Lakes. The sponsors say they are acting to protect ratepayers from being liable for turbines that could be destroyed by winter ice.
Pennsylvania: No Movement since 2010 Disappointment
In 2010, the Pennsylvania House of Representatives unanimously approved a bill to clear the way for wind in Lake Erie but the bill died after failing to get a hearing in the Senate.
The bill would have eliminated a 25-acre limit on leasing of Lake Erie bottomland, a restriction pushed into state law years earlier by opponents of a proposed casino, according to John Nikoloff, a lobbyist who represented a would-be wind developer.
Now, Nikoloff said in a recent interview, “it’s just not one of the (legislature’s) priorities .”
Nikoloff said the legislature’s focus has been on managing the growth of its shale gas drilling industry. New legislation to aid offshore wind won’t move, Nikoloff said, “unless there are companies that are seriously interested” in developing the lake’s resources.
Illinois: Making a Move?
The Illinois legislature in 2011 created the Lake Michigan Offshore Wind Energy Advisory Council, prompted by the city of Evanston’s interest in developing a farm.
The council worked with the state Department of Natural Resources (DNR) to produce a June 2012 report that recommended criteria for reviewing development applications, identifying favorable sites, and setting compensation levels for lakebed leasing.
In mid-May, an Illinois Senate Committee joined the House in approving a bill authorizing DNR to identify the best sites for offshore wind and to grant leases on them. HB 2753 was approved unanimously by the Senate Energy Committee after passing the House 90-21 in April.
Third time was the charm for Maryland Gov. Martin O’Malley this spring as he finally convinced lawmakers to approve his plan to subsidize the offshore wind industry off the Atlantic Coast.
The law puts Maryland in the race with PJM neighbors New Jersey, Delaware, Virginia and North Carolina in the contest to become home to an industry that officials hope will create thousands of jobs in the manufacture and servicing of offshore turbines.
But passing the legislation may prove to be the easy part. As this PJM Insider Special Report will demonstrate, realizing offshore wind’s environmental and economic development potential will require changes in federal policy and billions more in subsidies than Maryland and the other MidAtlantic states have committed to the effort thus far.
Potential
If the U.S. is to join Europe and China in deploying offshore wind, it will almost certainly happen first in the Atlantic, and the PJM states will be in the middle of it.
The Mid-Atlantic region has almost 300 GW of potential wind capacity in ocean waters less than 30 meters deep, more than a quarter of the U.S. shallow-water total and more than enough to supply all of the region’s power needs. PJM states bordering the Great Lakes also have considerable assets, led by Michigan and Ohio.
Offshore wind is attractive because of its potential to provide a large source of carbon-free generation without any fuel price risk.
The primary motivation for state officials, however, is the promise of jobs. Based on the experience in Europe, which has been building commercial-scale offshore wind for more than a decade, the U.S. Department of Energy’s National Renewable Energy Laboratory predicts every megawatt of offshore wind installed will create more than 20 job-years in manufacturing and installation and 0.8 permanent jobs in operation and maintenance.
The Obama administration estimates that 54 GW of offshore wind will be needed to reach its goal of boosting wind generation to 300 GW by 2035. Reaching the 54 GW goal, NREL says, would create $200 billion in economic activity and 43,000 permanent jobs in operations and maintenance and 1.1 million job-years in manufacturing, construction and engineering. “Most of the labor for offshore wind will draw from local and regional sources that cannot be easily outsourced overseas,” NREL said in a 2010 study.
No wonder politicians are giddy with the promise. Virginia Gov. Bob McDonnell pledged to make his state the “energy capital of the East Coast,” while O’Malley talked of making Maryland “the regional manufacturing hub for wind turbines.” New Jersey Gov. Chris Christie pledged to make the state a “national leader” in wind, calling the development of the state’s “renewable energy resources and industry … critical to our state’s manufacturing and technology future.”
Yet, it’s not clear whether the potential will be tapped any time in the next decade.
Cost Obstacles
The biggest reason is cost. Offshore wind’s capital costs are estimated at $6,000 per kW - almost three times that for land-based wind – because of the high cost of building at sea. Offshore turbines must be robust enough to withstand salt water and hurricane-force winds in the ocean and ice in the Great Lakes.
Offshore wind also has higher operations and maintenance and financing costs. The Energy Information Administration says the levelized cost of energy from offshore wind is $222/MWh (2008$), more than double the $87 for onshore wind and more than three times the $66 for natural gas advanced combined cycle plants. (EIA’s figures exclude any savings from the production tax or investment tax credits.)
These cost concerns have slowed development in PJM.
In Delaware, NRG Bluewater Wind put its proposed 450 MW wind farm on hold in 2011, cancelling a 25-year purchase power agreement with Delmarva Power & Light Co., after failing to find investment partners.
A proposed 25 MW pilot project off the coast of Atlantic City has been unable to persuade regulators or consumer advocates that it will be a net economic benefit. O’Malley may find his plans similarly hampered: the bill the Maryland legislature approved also requires a cost-benefit analysis that may prove difficult to meet.
Jobs: High transportation costs favor local production
What’s at stake?
A large commitment to offshore wind would lead to construction of new manufacturing facilities and jobs along the U.S. shores. Offshore wind turbines are typically larger than their shore-based counterparts and components can be expensive to build in facilities making land-based turbines. The larger size also increases transportation costs, which means new factories are likely to be built along the coastline where the turbines will eventually be deployed.
This wind turbine blade suffered $275,000 in damage in a 2011 traffic accident in Dubuque, Iowa. Offshore wind turbines are larger than their land-based counterparts, complicating transportation logistics and likely leading to shore-based manufacturing. (Source: US Department of Energy)
“Even though the United States has not yet developed an offshore wind project, the logistical requirements of transporting offshore machines would encourage [manufacturers] to build up U.S. manufacturing operations as soon as a long-term pipeline of likely project emerges,” NREL said.
At the American Wind Energy Association conference in Virginia Beach in October, the Boston Globe reported, “German developers talked about how the industry has transformed rusting homeland harbors into bustling ports, while British officials boasted that industry investment in offshore wind will leap from $8 billion in the last decade to $80 billion in the next eight years.”
Net Annual Additions equals new installations minus retirements. (Source: Global Wind Energy Council, Global Wind Statistics, 2012)
Offshore wind also will require ships to transport, install and maintain turbines. That would be a boon for U.S. shipbuilders, because the federal Jones Act requires that all goods transported between U.S. ports — wind farm foundations are considered ports — be carried in ships that were built domestically. Most existing vessels designed for offshore turbine installation are European-owned. Initially, U.S.-owned vessels built to service offshore drilling are likely to be in demand by wind developers.
Insufficient Demand to Lure Investment
But currently proposed projects and those that may result from the subsidies offered by states are not large enough to create the demand needed to spark substantial economic development on shore, according to a study released by the Department of Energy in February.
The study, by Navigant Consulting Inc., concludes that it will take demand of 500 to 800 MW per year for a minimum of five years to lure a U.S. manufacturing plant for offshore turbines. Commitments by the MidAtlantic states fall far short of creating that kind of project pipeline:
New Jersey’s Energy Master Plan set a goal of 1,100 MW of offshore wind by 2020.
Delaware and Maryland have proposed subsidies for 200 MW of offshore wind each.
If the three states’ combined commitment of 1,500 MW were built over five years, it would average only 300 MW per year. That could be enough to support a factory manufacturing a single component such as towers or blades, according to the Navigant study, which was based on interviews with suppliers.
Subsidies Needed to Overcome Price Disadvantage
Thanks to more aggressive climate change goals and large government subsidies, Europe has grown its offshore wind capacity to 5,400 MW over more than a decade while the U.S. — second only to China in land-based wind capacity — has no commercial-scale wind power offshore. Not coincidentally, virtually all of the manufacturing of offshore turbines is owned by non-U.S. companies.
Current federal incentives — Congress’ one-year renewal of the Production Tax Credit and Investment Tax Credit for wind power — also fall short, says Sen. Tom Carper, a Democrat from Delaware.
Confirmed Global Offshire Wind Turbine Deliveries Though YE 2011 (MWs) (Source: BTM, 2011, a part of Navigant)
Carper and Maine Republican Susan Collins reintroduced a bill in February that would make the first 3,000 megawatts of offshore wind energy capacity eligible for the investment tax credit. Tying the credit to a capacity limit rather than having an expiration date will allow the long-term planning that offshore wind requires, Carper says. The bill, which Carper initially introduced in 2011, has been assigned to the Senate Finance Committee but has not had any hearings to date.
Other offshore wind supporters say it will take a fee on carbon pollution to give offshore wind a chance to build the scale economies to compete against fossil fuel-fired generation.
In a February 2013 study commissioned by the Center for American Progress and groups including the Sierra Club, The Brattle Group predicted that the cost of offshore wind could reach “grid parity” with gas combustion turbines by 2024 to 2030. The analysis does not include production or investment tax credits but does assume a carbon price on coal and natural gas-fired generation that increases from $8/mwh in 2014 to almost $62/mwh in 2030 (2012 $). Existing tax subsidies for gas production also are eliminated in this scenario.
The 2030 estimate assumes a 5% “learning rate” for offshore wind — the rate at which costs decline for each doubling of the installed capacity. At a 10% learning rate, grid parity is reached by 2024. Onshore wind cut its capital costs by a learning rate of 15%, the Interior Department reported in a 2006 study.
Building 54 gigawatts of offshore wind will require ratepayer subsidies, or “learning investment,” of $18.5 billion to $52 billion with a carbon fee and $79 billion to $150 billion without one, Brattle estimated. That translates to an average rate increase of up to 1.7% nationwide, or 3% for the Atlantic and Great Lake states, if costs are concentrated in those coastal regions where the earliest development is likely.
Many are willing to pay a modest premium to build a cleaner source of generation that also acts as a hedge against rising fuel (i.e. natural gas) prices.
A Washington Post poll in February found 58% of Maryland residents supported O’Malley’s offshore wind initiative, which will add up to $1.50 to residential customers’ monthly bills. Thirty-nine percent were opposed. A 2012 poll on a prior version of the legislation — which would have imposed a $2 surcharge — won support from 55% of respondents, with 42% opposed.
Some are willing to pay much more. In a campaign launched in mid-April to persuade utilities and power marketers of customer demand, the developers of a proposed Lake Erie wind farm off Cleveland have gotten almost 1,000 retail customers to sign a “Power Pledge” indicating their willingness to pay extra for offshore wind. The signers said they were willing to see their electric bills increase $10 a month. The developers hope to secure 10,000 signatures by the end of the summer.
The Pacific Coast has higher wind speeds than the Atlantic and the Gulf of Mexico, but exploiting its deep waters will require the development of floating turbines. (Source: National Renewable Energy Laboratory)
But in addition to state support for rate increases, offshore wind will need Washington’s support for a carbon fee. The Brattle study found that subsidies would need to be three to four times higher without a carbon fee than with one.
Congress rejected efforts to impose carbon fees through a cap and trade system in 2009 and there has been little movement in Washington toward such a fee since.
Lacking a carbon tax, the Obama administration’s efforts on behalf of offshore wind have been limited to streamlining the permitting process and providing grants for research and development.
The Department of Energy has committed more than $270 million in funding for research and development of offshore wind since fiscal 2009.
While they need help from Washington, policymakers in the PJM states also will have to increase their commitment to offshore wind considerably to create enough demand to lure the jobs they crave. Until then, their efforts will be little but hot air.
WASHINGTON — The Federal Energy Regulatory Commission signaled today that it will increase its scrutiny of the PJM-MISO Joint Common Market process amid complaints that PJM is improperly limiting MISO generation from full participation in its capacity market.
FERC commissioners indicated their concern in comments following presentations by representatives of PJM, MISO and state regulators at today’s commission meeting.
RTO representatives and state regulators made their cases before the Federal Energy Regulatory Commission in a dispute over capacity deliverability across the PJM-MISO “seam.” Facing the camera from left: Joseph Bowring and David Patton, independent market monitors for PJM and MISO, respectively; Commissioner Greg White, Michigan Public Service Commission; Chairman Phil Montgomery, Wisconsin Public Service Commission; Kari Bennett, Indiana Utility Regulatory Commission; Andy Ott, PJM executive vice president for markets, and Clair Moeller, MISO executive vice president for transmission and technology. (Source: FERC)
The commission ordered the presentation as part of a docket it created last June to determine whether it needs to get more involved in a long-standing dispute between PJM and MISO over PJM’s rules for determining the volume of capacity that can be imported across the PJM-MISO “seam.”
PJM: No Artificial Barriers
Andy Ott, PJM executive vice president for markets, told the commission that MISO’s complaints are belied by PJM’s 2016/17 capacity market auction, in which 4,700 MW of MISO capacity bid, all of it clearing. That was more than double the volume that bid in last year’s base auction; about one quarter of the total came from territory new to MISO, including the Entergy transmission system.
“We really haven’t seen barriers” to MISO generation, Ott said. Ott said the commission should not set deadlines for a resolution of the dispute but continue monitoring the JCM stakeholder process through its staff, calling it a “very powerful” force in ensuring the talks progress.
But Commissioner Tony Clark was unconvinced that what he called the commission’s “benign neglect” stance had been effective: “Staff has monitored [JCM] for the last six or seven years,” he said. “It stalled.”
Other commissioners also signaled impatience with the status quo.
Commissioner Cheryl LaFleur said that since FERC’s ill-fated attempt at imposing a Standard Market Design, the agency has allowed regional transmission operators to develop different market structures and operating procedures. While PJM and MISO have done the most work of any two RTOs on seams issues, she said, “There’s still a long, long list of things to work on.”
Deadline `Discipline’
Commissioner Philip Moeller said the resumption of the JCM process last year was “overdue” and that the talks could benefit from the “discipline of a deadline.”
“To the extent that this becomes a reliability issue, it’s absolutely something we can’t ignore,” he said, referring to MISO’s concerns that its current capacity surplus may become a shortage in several years, requiring it to seek capacity imports from PJM.
Commissioner John R. Norris said MISO may be correct in its complaint that PJM rules are artificially restricting capacity imports below physical transport limits. “My sense is, there is a there there.”
PJM and MISO have been holding monthly JCM meetings since July but MISO says the talks have made little progress in addressing capacity deliverability. In a filing in January, MISO asked the commission to set deadlines for resolution of the issue. PJM responded that the commission should reject MISO’s request and close the docket.
State Regulators’ `Blueprint’
Commissioner Clark said the commission should follow the “blueprint” proposed by state regulators last week. The joint filing by the Organization of PJM States (OPSI) and the Organization of MISO States (OMS) called for fact finding to identify methodologies for: determining transfer capability between MISO and PJM; the feasibility of potential revisions to existing rules and a way to compare the costs and benefits of such changes.
The states said the JCM should consider hiring an independent consultant to help mediate if PJM and MISO are unable to agree.
“It is not helpful for either RTO to insist upon an end-result or outcome without having supportive documentation and analysis,” the groups said. “Without collaborative involvement from both RTOs the output of any fact finding and subsequent analysis would likely be unreliable.”
That existential question was raised at Wednesday’s Market Implementation Committee meeting by Customized Energy Solutions’ Bill Schofield who has been voicing concerns for months about the growing stakeholder workload.
Schofield, who represents the PJM Public Power Coalition, used an analogy from his horse-riding wife to make his point. Given unlimited access to food, he said, “Many ponies will basically eat themselves to death.”
Fat Pony (Source: Minnesota Farriers Association at MinnesotaFarriers.Com)
Noting that PJM stakeholders are adding new problem statements and work groups faster than they are completing them, he observed: “We seem to be a bunch of ponies here.”
Schofield’s concern was borne out by MIC chair Adrien Ford, who said PJM was having trouble providing enough facilitators to run meetings on the problem statements. Ford said no facilitators would be available to take on a new problem statement before late summer.
The discussion came as the MIC discussed where to slot its latest problem statement — a review of the FTR forfeiture rule for increment and decrement transactions — in its new work plan. The plan lists 14 issues under study.
Jeffrey Mayes, general counsel of Monitoring Analytics, said the FTR issue, which was assigned to the MIC May 30, shouldn’t be taken up until at least October. Mayes said the committee should focus first on a problem statement sponsored by the monitor to consider ending compensation “adders” for frequently mitigated generating units (FMU). (See “PJM Reconsiders Adders on Cost-Capped Generators.”)
David Pratzon, who represents generators, disagreed, saying the stakeholder consensus was that FMUs are a “small-dollar issue.”
“FTRs affect a whole lot more people in the market,” he said.
Ford sided with Pratzon and said the FTR forfeiture issue will be scheduled before the FMU inquiry.
The Operating Committee Tuesday approved changes to Manuals 14 and 36. The changes go next to the Markets and Reliability Committee for final approval.
Manual 14D: Generator Operational Requirements
Reason for changes: Conforming with other manuals; revised NERC standard; updated information; and addition of Wind Unit Dispatchability Check List.
Impact:
Multiple sections revised to replace outdated references.
Section 7.1.1, Generator Real-Power Control: Revised for consistency with M-36.
Section 7.1.3, Notification to PJM for Reactive Power Resource Status during Unit Start-up: revised to reflect changes in NERC Standard VAR-002-2b, R1, effective July 1.
Section 7.3, Critical Information and Reporting Requirements: Added references to PJM peak period maintenance season and changed notification time from 30 minutes to 20 minutes for consistency with 7.4.
Section 7.4 Synchronization and Disconnection Procedures: Revised to include notification times for synchronizing and disconnecting generators from the system.
Section 8, Wind Farms Requirements: Revised to include references to Attachments L & M.
Attachment H, PJM Generation and Transmission Interconnection Planning Process Flow Diagram, revised for consistency with Manual M-14A/C.
Attachment M, Wind Unit Dispatchability Check List: New attachment.
PJM contact: Glen Boyle
Manual 36: System Restoration
Reason for changes: Annual review, incorporating suggested changes from the RFC/SERC audit.
Impact:
Attachment G updated to reflect revised EOP-005-2, Restoration Plan Coordination/Approval Process.
Attachment B updated for consistency with other RTOs (information to be exchanged prior to interconnection).
Updates Attachment H – Underfrequency Load Shed Tables.
Adds Attachment I to map manual sections to EOP-005-2 and EOP-006-2.
Minor grammatical changes throughout.
Attachment F update – Transmission Owner and black start supporting document references
Adds specific references to TO restoration plans
Allows future updates in separate file to avoid repeated manual updates requiring stakeholder approval.
PJM’s summer 2013 emergency preparedness drill exposed several communications problems and the need for additional training, PJM’s Bill Powell told the Operating Committee Tuesday. Powell identified several issues in his debriefing on the May 14 drill:
One company was unable to submit correct Supplemental Status Report (SSR) data in the Dispatcher Applications and Reporting Tool (eDART); two companies requested additional training on SSR.
Several companies complained of garbled satellite phone messages.
Several companies said that messages on the All Call notification system were too long.
Several companies identified the need to perform additional internal training or update internal processes.
PJM did not post the Manual Load Dump event on the Emergency Procedures posting application at the same time as the Manual Load Dump All Call. Several companies requested clarification regarding the time to be used in event of an actual load dump situation; PJM said the All Call time will be used.
Several inconsistencies were noted in drill sequence and accompanying All Call messages regarding loading max emergency combustion turbines first instead of steam units. All Call drill wording did not match some of Manual 13. Future drill messages will be corrected to match PJM manuals.
PJM will begin posting temporary transmission rating changes on the OASIS System Information page effective June 19. The postings will contain current and future rating changes, including the cause of the change and its expected duration. The existing ratings postings will be unchanged.
Transmission owners should consider locating staff in 500 kV substations in advance of future hurricanes, and PJM should be quicker to take generation off-line as load is lost, the Operations Committee was told Tuesday.
PJM’s Mike Bryson briefed the committee on lessons learned from Hurricane Sandy, the results of a detailed review by the System Operations Subcommittee Transmission group (SOS-T).
Among the key lessons:
Staffing:
TOs that manned their 500 kV substations were able to respond to Remote Terminal Unit (RTU) failures quickly and had response crews geographically dispersed, allowing them to get to other substations more rapidly. RTUs collect data from transducers at remote locations and convert it for transmission to the Supervisory Control and Data Acquisition (SCADA) system used to monitor and control the grid.
Emergency staffing plans should be amended to include provisions for conditions in which control room staff cannot leave due to weather or road conditions. PJM discovered this vulnerability when fallen trees blocked the road in both directions outside its Advanced Second Control Center (AC2) in Milford, PA.
Generation planning:
Fearing the loss of load and large generators during the storm, PJM ran additional local generation. But while load was lost, generation remained on-line, resulting in high voltage conditions. PJM said it should have taken generation off-line more quickly. Inspections found that none of the equipment that experienced high voltage during the October storm was damaged.
500kV line switching:
The storm required PJM to perform 500 kV line switching for voltage control for the first time. Before implementing the switching, PJM reviewed generation on-line, potential interactions with Special Protection Schemes, transient stability and Nuclear Plant Interface Requirements. The SOS-T recommended developing a checklist for future use to ensure these studies are consistent and that switching doesn’t create unanticipated problems.
Phones:
Service on cell phones and landlines was unavailable or spotty but text messages were successfully transmitted. The committee recommended having text-capable phones for operators and crews.
Customer Outage Reporting:
PJM’s calls to TOs for verbal updates on customer outages distracted the TOs from operations and restoration. PJM plans to develop a tool to scrape the TO websites for these updates.
The Planning Committee Thursday approved changes to Manual 19: Load Forecasting and Analysis. The changes go next to the Markets and Reliability Committee.
Reason for changes: Integration of East Kentucky Power Cooperative (EKPC), addition of annual demand resources; and need to ensure accuracy of load shed programs.
Impact:
Adds EKPC to load forecast model;
Revises assumption for winter load management;
Makes minor typo fixes and clarifications for NERC audits;
Changes demand resources available in winter months due to addition of annual DR product; and
Codifies guidelines for switch operability studies for load management programs. The guidelines are designed to ensure the accuracy of load shed estimates for participants in Direct Load Control programs. The study must be designed for a minimum 90% confidence level and based on a randomly selected sample from the entire population of participating customers. No customers can be excluded.
