Senior Vice President for Operations Mike Kormos last week marked his 25th anniversary at PJM, making him the longest serving executive with the RTO.
He reported for his first day of work in PJM’s control room on June 27, 1988.
Today, Kormos oversees system operations, system planning, information and technology services, security and regional coordination.
He holds a B.S. in electrical engineering from Drexel University and an MBA from Villanova University.
MISO and its supporters say the decisions by FirstEnergy and Duke Energy Ohio to leave MISO for PJM are proof that deliverability issues across the RTOs’ borders are due to PJM’s modeling rather than any physical constraints. But others — including FirstEnergy and Duke — say they are incorrect.
When it was in MISO, Duke’s energy and capacity was not considered deliverable into the PJM markets, the Indiana Utility Regulatory Commission contends. After Duke joined PJM in January 2012, “and without the building of any additional transmission facilities, deliverability of electricity and capacity was no longer an issue,” the state said in a filing with FERC.
PJM says MISO and its supporters are ignoring the fact that PJM assumed dispatch of Duke and FirstEnergy’s generation, and that the companies’ loads also moved to PJM.
Duke said its Ohio affiliate left MISO because it jointly owned transmission and generation with PJM utilities, and because PJM is designed to accommodate retail choice.
FirstEnergy said its 2011 move allowed the company to realign its operations into a single RTO. American Transmission Systems, Inc. (ATSI), FirstEnergy’s transmission affiliate, has 32 interconnections with PJM, but only three with MISO, the company said in a FERC filing in August.
“The ATSI integration into PJM resulted in an addition of load to the PJM footprint that exceeded the amount of FirstEnergy generation capacity that was integrated, and therefore, regardless of the move to PJM, there was no increase in capacity sales, net of FirstEnergy load,” FirstEnergy said.
“Moreover, following the move to PJM, PJM obtained scheduling, dispatch and operational control over FirstEnergy’s transmission facilities and included FirstEnergy’s generation and load in its planning models. PJM could not have had such scheduling, dispatch and operational control over FirstEnergy’s facilities when FirstEnergy was in MISO.”
Below is a summary of the issues scheduled to be brought to a vote at the Markets and Reliability Committee and Members Committee meetings 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 PJM Insider.
PJM Insider will be in Wilmington covering the discussions and votes. See next week’s newsletter for a full report.
A. MRC will be asked to endorse changes to Manual 11 affecting regulation rules, hydropower generators, station manning and shortage pricing. The changes provide clarifications, correct errors and conform to other manuals.
Manual Changes Approved by the Market Implementation Committee on June 5, 2013B. MRC will be asked to approve changes to Manual 14D: Generation Operational Requirements. The changes conform to other manuals and reflect a revised NERC standard, updated information and addition of the Wind Unit Dispatchability Check List.
Manual Changes Approved by Operating Committee on June 4, 2013Members will be asked to select between two proposed changes to the modeling of Financial Transmission Rights. The two proposals from the Financial Transmission Rights Task Force (FTRTF) received near-unanimous support from the Market Implementation Committee in May. A third option failed with less than 40% support and a vote on a fourth option was postponed.
Under the first option (FTR Task Force option 2J), PJM “may model normal facility capability limits, if possible, for all Stage 1A over allocated facilities in FTR Auctions.”
The second option (option 3G), would allow PJM to “model normal facility capability limits, if possible, on facilities which are infeasible as a result of modeled transmission outages in monthly FTR Auctions.”
MIC OKs Options to Reduce FTR ShortfallsPJM seeks stakeholder approval for contingency plans to respond to an Internet outage that forces the RTO to suspend the day-ahead market. PJM has no procedures for dealing with an Internet outage that could prevent the RTO from receiving participant data needed to solve the day-ahead market.
Under the proposed tariff changes, all market settlements would be done in real time.
PJM Seeks OK to Suspend Day-Ahead Market after Internet OutageMRC will vote on a recommended change to the cost allocation of Market Efficiency projects. The proposal, developed by the Regional Planning Process Task Force, would calculate benefits on a 50/50 ratio based on its impact on production costs and net load payments (energy benefits) or impact on capacity costs and net capacity payments (capacity benefits). The proposal received overwhelming support from respondents surveyed by the task force. Only 29% of respondents favored continuing the current method, under which 70% of benefits are calculated based on production or capacity cost savings.
“Multi-Driver” Transmission Proposal ChallengedPJM will ask approval of a problem statement to consider how to treat demand response as operational capacity resources. PJM expects to deploy DR in system operations with increasing frequency due to DR’s increasing share of capacity and generation plant retirements. Use of DR under current rules creates potential operational problems. Potential results from the inquiry include:
MRC will be asked to approve the charter for a task force it created in March to study potential reliability problems resulting from PJM’s increasing reliability on gas-fired generation.
The proposed charter calls on the Gas Electric Senior Task Force (GESTF) to provide education, prioritize issues and draft problem statements and solutions for each issue.
The task force is expected to work last through the 2016/2017 delivery year, during which PJM expects significant additions of new gas-fired generating capacity to replace coal retirements. All PJM stakeholders may appoint representatives to the task force.
Sean McNamara will be the chairperson and Rami Dirani the secretary.
Task Force to Study Gas-Electric CoordinationThe committee will be asked to approve corrections to errors inserted in Schedule 1 of the PJM Operating Agreement and Attachment K of the tariff in 2008 and 2009.
One correction will clarify how deviations occurring within one zone are associated with PJM’s Eastern or Western region for purposes of Operating Reserve charges. The other will insert a cross reference to tie language concerning forgiveness of positive demand deviations to the shortage pricing “trigger.”
Robert Weishaar, an attorney who represents industrial energy users, will ask MRC to approve a problem statement that could result in requirements that transmission owners make tariff filings disclosing their calculation of total hourly energy obligations, peak load contributions, and network service peak loads. The calculations are used to allocate energy, capacity, and transmission cost responsibility among load serving entities.
Weishaar said two-thirds of PJM’s transmission owners have failed to file tariffs disclosing the methodology they use to make their calculations, in violation of Federal Energy Regulatory Commission rules.
Industrials Call for Transparency in Transmission Owner CalculationsA representative of the Electricity Storage Association will ask MRC to approve a problem statement that would develop rules for including advanced energy storage technologies in its ancillary services and capacity markets.
Although pumped hydro participates in PJM markets, the RTO has no rules for advanced technologies such as batteries, flywheels, thermal storage and compressed air, a representative of the Electric Storage Association told MRC members.
Advanced Energy Storage ProposedPJM will ask MRC to approve a problem statement that would seek to draft tariff language explicitly listing rules for wind resources to receive Lost Opportunity Cost credits.
Although the requirements are described in PJM Manuals, the Federal Energy Regulatory Commission said in a May 29 order that the requirements should be approved by the commission and listed in the PJM Tariff. “PJM has not shown that it is just and reasonable for PJM to have the discretion to reset compensation levels retroactively when neither the particular circumstances that would trigger PJM’s actions nor the financial consequences are specified in the tariff,” the commission wrote.
The committee will be asked to approve revisions to Manual 15: Cost Development regarding cost-based offers in the regulation market. Information on cost-based offers is being moved into Manual 15 from Manual 11.
PJM will seek endorsement of Tariff revisions approved last month by MRC requiring new generators to pay for the installation and maintenance of phasor measurement units (PMUs). PJM will pay for the communication link with the PMUs, which provide data that helps PJM in real-time operations and system planning. The Interconnection Service Agreement will be changed to require installation of PMUs at new interconnections for generators with nameplate ratings of 100MVA or larger.
MRC Approvals 5/30/13: PMU Costs, CFTC Order, UTC CreditThe committee will be asked to endorse PJM’s proposed filing in response to FERC’s April order requiring the RTO to seek commission approval for new rules imposed last year on demand response providers. FERC said the changes required amendments to the PJM tariff and not just its manuals. Tariff changes require commission approval while manual changes don’t.
The new rules will require Curtailment Service Providers seeking to participate in capacity auctions to file “Sell Offer Plans,” including information about the provider’s customers. CSPs also must have a company officer sign a certification attesting to the company’s intent to physically deliver MWs.
FERC Remands DR Information Requirements
If the U.S. is to enter the offshore wind industry, it will likely happen first on the Atlantic Coast. The coastline’s shallow waters are similar to those in Europe, which has been building utility-scale offshore wind for more than a decade. And more than a quarter of the U.S. wind capacity in shallow water — depths of 30 meters or less — is in the PJM region, where New Jersey, Delaware, Maryland, Virginia and North Carolina are all hoping to be the first to get into the water.
Below is a state-by-state status report.
It’s been almost three years since New Jersey Gov. Chris Christie signed legislation committing the state to purchase 1,100 MW of offshore wind by 2020.
But a 2010 law that offered up to $100 million in state tax credits to any turbine manufacturer that located in the state expired at the end of 2012 with no takers. The only project proposed to date, a 25 MW pilot, has been unable to win approval from state ratemakers.
Fishermen’s Energy, LLC’s proposal to install five turbines in state waters three miles off of Atlantic City won approval to begin construction last July from the Army Corps of Engineers. If the pilot is successful, Fishermen’s said, it could be followed by a 330 MW commercial-scale project in federal waters.
The project would be largely financed and owned by Chinese turbine manufacturer Xiangtan Electric Manufacturing Group, Ltd. (XEMC). The People’s Government of Hunan Province is a major owner of the company.
But studies commissioned by both the Board of Public Utilities and the Division of Rate Counsel, which represents consumers, found that the Fishermen’s Energy pilot failed to provide a “net economic benefit” to New Jersey ratepayers. The rate counsel analysis concluded the project would cost $282 million over 20 years, requiring $208 million in ratepayer subsidies for above-market power costs and a negative net present value of $132 million.
The Rate Counsel analysis, by David E. Dismukes, of Acadian Consulting Group, said project developers’ claims of net benefits “rely heavily” on the prediction that the farm will boost Atlantic City’s tourism. The developers claimed that 16 percent of Atlantic City’s 28 million annual visitors would spend extra time in town to visit the wind farm. Dismukes said there was no basis for that claim, noting that it suggested the wind farm would have more visitors than the Washington Monument or New York’s Museum of Modern Art. Europe’s wind farms have had no significant impact on tourism, Dismukes said.
BPU’s consultants, Boston Pacific Co. and OutSmart BV, also concluded that the project failed to clear the economic benefit hurdle, though their specific conclusions were redacted from the report released publicly.
The BPU report also cited concerns over the project’s technical risk (use of direct-drive turbines by XEMC that have not been proven commercially) and financial strength (noting that XEMC’s financial statements do not meet U.S. accounting standards). The consultants also questioned the credentials of the developers’ management, noting that only one employee has significant experience in offshore wind development.
Rhonda Jackson, spokeswoman for Fishermen’s Energy told PJM Insider last week that “a lot has changed” since the BPU and Rate Counsel reports. She declined to provide specifics because the company is making another attempt to win approval through negotiations with the parties.
Legislation introduced in the New Jersey legislature earlier this year would ask PJM to include the New Jersey Energy Link, a proposed north-south transmission line about 10 miles offshore, in its Regional Transmission Expansion Plan (RTEP). The bill would commit the state to paying for the project under the “State Agreement” cost allocation plan outlined by PJM in its Order 1000 compliance filing. (See “PJM’s To Do List.”) Costs would be allocated proportionately to each load-serving entity in the state.
The project would be the northernmost portion of the Atlantic Wind Connection, a proposed “backbone” to transport offshore wind as far south as Virginia.
Atlantic Wind president Markian Melnyk says New Jersey should build transmission “proactively’ to serve wind, as was done in California’s Tehachapi Pass, Texas’ CREZ zone and the Midwest’s multi-value projects serving “energy zones.”
“New Jersey’s been a leader in solar,” he said during a panel discussion at the Energy Bar Association’s Northeast chapter meeting in Newark June 5. “They want to be a leader in wind but the onshore wind resources are poor. The offshore potential of wind is huge.”
Atlantic Wind officials say the New Jersey project will serve two purposes, transporting offshore power when the wind is blowing and relieving transmission congestion — which often prevents North Jersey from access to cheap nuclear power in South Jersey — when it’s not.
Atlantic Wind CEO Bob Mitchell said the New Jersey Energy Link will have a $2 billion net present value over 20 years, with its $1.8 billion construction cost offset by $1.5 billion in avoided transmission upgrades on land, $800 million in reduced congestion costs and $1.5 billion in reduced Renewable Energy Credit (REC) costs versus radial lines.
Also speaking at the Energy Bar conference, Stefanie Brand, director of the Division of Rate Counsel, said the line should not be considered until there is offshore generation for it to service. “If the goal is bringing power from South Jersey to North Jersey, there may be much more cost effective solutions,” she said.
The bill has bipartisan sponsorship in both the Senate and Assembly, with both North and South Jersey representation. Among the sponsors are Senate President Stephen M. Sweeney and Assembly Appropriations Chairman John J. Burzichelli.
The two represent the Delaware River port of Paulsboro, N.J., which AWC and XEMC have identified as the likely site of manufacturing operations to support their projects. XEMC identified Paulsboro as the site of a proposed turbine assembly plant. Atlantic Wind chose it as a site for building offshore converter platforms, which it said would generate at least 500 jobs.
AWC also has lined up Google as an investor and hired the consulting firm of former Homeland Security Secretary Michael Chertoff to do a study that concluded the project would make the New Jersey grid more resistant to an attack or natural disaster.
AWC CEO Bob Mitchell said approval of the legislation is “crucial” to getting the project built.
Mitchell said the developers originally planned to build in phases over 10 years. “So the first phase is going to be done in New Jersey. Whether or not any of the other plans get developed I can’t say… If the other ones don’t get built it wouldn’t be a huge surprise to me.”
Delaware’s offshore wind plans have been in limbo since 2011, when an affiliate of NRG Energy Inc. cancelled a 25-year power purchase agreement with Delmarva Power & Light Co. for a 450 MW project.
In October 2012, the Interior Department’s Bureau of Ocean Energy Management awarded NRG Bluewater Wind a lease granting it exclusive rights to collect wind speed data and develop a construction plan for a 96,430-acre site 11 miles offshore. It was the second utility-scale lease issued by Interior, following its award to the Cape Wind project near Nantucket, Mass.
But while Cape Wind hopes to begin construction by the end of the year, the Delaware lease may sit unused for years.
In December 2011, NRG exercised an exit clause in its PPA, saying that Congress’ decision to eliminate funding for the Department of Energy’s loan guarantee program for offshore wind, and uncertainty over the future of the federal investment and production tax credits for wind farms, left the project “financially untenable.” The company said it had been rejected by more than two dozen prospective investors.
Delmarva would have purchased 200 MW of energy and capacity from the wind farm at a cost of $98.93/MWh for energy and $70.23/kW-year for capacity (2007 $).
The agreement also called for Delmarva to pay NRG $15.32/MWh for renewable energy credits (RECs). The state granted Delmarva a 350% credit on offshore wind, meaning the utility will receive credit for 200 MW toward its RPS obligations while purchasing only 57 MW of RECs. That allowed NRG to sell the RECs associated with the remaining 143 MW to other utilities.
The 350% credit was a tradeoff to minimize the impact on Delmarva ratepayers. It meant that the amount of renewable energy needed to be produced to satisfy the state’s RPS would be lower than the 20% RPS goal.
A consultant hired by the state Public Service Commission estimated a Delmarva ratepayer using 1,000 kWh per month would pay a levelized cost of 70 cents (2007 $) monthly to support the wind farm, starting at $1.50 in 2014 and turning to monthly savings by 2031.
In its announcement canceling the PPA, NRG said it would preserve its offshore assets until the market improves enough for it to find investors. NRG spokesman David Gaier told PJM Insider that the company will specify the size of the project and density of the turbine layout for its project in a Site Assessment Plan, due December 1. “Signing the commercial lease for the [project] is one of those important steps in preserving our valuable offshore wind development assets,” Gaier said.
NRG will have until June 2017 to submit the Construction and Operations Plan. If it fails to do so by the deadline, BOEM can cancel the lease.
The newly-passed Maryland legislation creates a 200 MW “carve out” for offshore wind with developers receiving payments through Offshore Renewable Energy Credits (ORECs). Based on the maximum rate increase permitted under the bill ($1.50 per month for average residential customers, 1.5% for most businesses) the ratepayer subsidies will total $1.7 billion.
The bill also creates an $8.5 million Offshore Wind Business Development Fund to provide employee training and development assistance for fledgling offshore wind businesses.
The 80,000 acres BOEM designated for development off of Maryland will be leased in two portions. This will allow Maryland to force the winners of the two leases to bid against each other for the state incentives, potentially driving prices down. The losing leaseholder likely won’t develop the site because “it won’t be financeable,” said Jim Lanard, president of the Offshore Wind Development Coalition, which represents wind developers and companies that service them.
The Maryland Public Service Commission must determine a pricing schedule for the ORECs by July 1, 2014. The law sets a minimum 90-day window for developers to submit proposals, followed by a 180-day evaluation period by regulators.
The law’s cost-benefit analysis includes in-state manufacturing, employment and environmental benefits. “It’s going to be an easier standard to meet” than New Jersey’s, Lanard said.
Lanard suggested Maryland might consider teaming up with Delaware because a single 400-MW wind farm would achieve more scale economies than two 200-MW projects. The Maryland Wind Energy Area, which could support 1,615 MW, sits just east of the Delaware-Maryland border.
Unlike the other coastal states in PJM, Virginia does not have a mandatory Renewable Portfolio Standard. Virginia also has no state subsidy for offshore wind. Instead, it hopes to capitalize on what it calls the “competitive advantage” of its Norfolk port, the deepest on the East Coast.
The state created the Virginia Wind Development Authority in 2010 to collect wind and ocean data, identify barriers to development and coordinate communications with the federal government.
Based on recommendations from the authority’s 2012 annual report, the state has agreed to provide $1.4 million to aid data collection and provide matching funds for grants funding preconstruction development.
Eight companies, including Dominion Resources, Iberdrola Renewables and Fishermen’s Energy filed expressions of commercial interest in the Virginia Wind Energy Area (WEA) in response to BOEM’s February 2012 solicitation.
Dominion, the state’s largest utility, said if it wins the lease it will erect a meteorological tower to study wind strength and patterns.
“Dominion absolutely controls the market,” Lanard said. “The only way they’ll be engaged in offshore wind is if they win the lease.”
Virginia consumers do not have retail choice. Thus Virginia wind developers will likely need to market their output through Dominion, the state’s dominant utility and owner of the monopoly service territory along the coast.
BOEM ruled in March that there was “no competitive interest” in a wind energy research area sought by Virginia’s Department of Mines Minerals and Energy (DMME). The decision will allow DMME to install two monitoring platforms to collect data on wind velocities, water levels, waves, and bird and bat activities. Virginia will make the data collected available publicly in hopes of attracting developers to Virginia’s WEA.
DMME also awarded a $750,000 grant in 2011 to Poseidon Atlantic, of Alexandria, to develop pre-construction phases of a wind turbine test and certification facility on Virginia’s Eastern Shore that it hopes will be used by land-based and offshore wind projects globally.
North Carolina has the best ocean wind in PJM — three times the potential of number two New Jersey — but has done little to exploit it to date.
A bill introduced in 2011 that would have required state regulators to issue a request for proposals for 2,500 MW of offshore wind capacity died in committee and hasn’t been reintroduced. Duke Energy Carolinas opposed the bill.
In March, the Bureau of Ocean Energy Management announced that five companies had expressed interest in three potential wind leasing areas: Virginia Electric and Power Co.; EDF Renewable Development, Inc.; Fishermen’s Energy, LLC; Green Sail Energy, LLC, and Outer Banks Ocean Energy, LLC.
BOEM will review the five submissions to determine which meet the technical and financial qualifications to be eligible to bid on a future commercial lease.
Brian O’Hara, president of the Southeastern Coastal Wind Coalition, in Raleigh, NC, said he and other supporters are attempting to craft a strategy that will be supported by utilities in North Carolina, which unlike most of PJM, continues to run a vertically-integrated, cost-of-service model.
Republican Gov. Pat McCrory has endorsed offshore wind as part of his “all-of-the-above” energy policy but has not endorsed subsidies or outlined any other plan of action. McCrory’s office did not respond to requests for comment.
“We just haven’t gotten that far down the path in” discussions about state subsidies for the first wind farms, O’Hara said.
The Interior Department’s Bureau of Ocean Energy Management (BOEM) oversees development of the nation’s oil, gas, mineral and renewable energy resources on the Outer Continental Shelf.
The agency issued final regulations for offshore wind leasing in April 2009. Since then, it has issued two commercial leases, in 2010 to Cape Wind Associates, LLC for a 468-MW, 130-turbine project between Cape Cod, Martha’s Vineyard and Nantucket Island, and to NRG Energy, Inc. for the right to development a 96,430-acre area off Delaware.
The $2.6 billion Cape Wind project has agreements with utilities to purchase about 75% of its output. It has hired Barclays to help it raise financing and hopes to begin construction later this year.
The NRG lease was the first issued under Interior’s “Smart from the Start” initiative, which employs a comprehensive planning approach to reduce conflicts with other offshore interests before parcels are put out for lease. The Delaware project is in limbo after NRG was unable to find investors despite a 25-year purchase power agreement with Delmarva Power & Light Co. (See related story, “PJM States Seek `First Mover’ Status.”)
BOEM has established a four-stage process to offshore wind development:
This stage is intended to identify potential conflicts between commercial wind development and other uses, such as commercial fishing and shipping traffic. In the Rhode Island/Massachusetts call, for example, the agency removed the “Cox’s Ledge” fishing grounds from consideration for wind power.
Environmental reviews are limited to consideration of vessel survey work and resource assessment, not commercial wind development.
At the end of the process, the area selected for commercial leasing is designated a Wind Energy Area (WEA).
BOEM will hold an auction in late July for the 164,750-acre Wind Energy Area off of Rhode Island and Massachusetts. BOEM also is expected to auction 112,800 acres off Virginia later this year.
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.
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.
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.
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.
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.
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:
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.
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 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.
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.
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.
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.
by Rich Heidorn Jr.
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.
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.
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.
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.
“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.”
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.
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:
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.
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.
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.
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.
By Rich Heidorn Jr.
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.
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.”
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.”
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.
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.”
By Rich Heidorn Jr.
Is PJM in danger of eating itself to death?
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.”
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.
