Page 1366 – RTO Insider

June 12, 2018March 25, 2025

Five Questions on Trump’s Coal, Nuke Bailout

By Rich Heidorn Jr.

More than a week after President Trump directed Energy Secretary Rick Perry to prevent additional coal and nuclear plant retirements, the administration has provided no additional details on how it plans to implement the bailouts or how much they will cost.

With no answers coming from D.C., analysts and others have been left to speculate on the bailout’s potential impact. Here’s five important questions and possible answers.

Can the Trump/Perry Plan Survive Legal Challenges?

Trump’s directive came after the leak of a 40-page draft Department of Energy memorandum that said coal and nuclear plant retirements are a threat to national security, in part because natural gas pipelines could be subject to terrorist attacks. It called for keeping at-risk plants alive through capacity and energy payments for at least two years while the department studies the risks and then creates a “Strategic Electric Generation Reserve.”

The memo cited the Defense Production Act of 1950 (DPA) — enacted to aid the nation’s civil defenses and war mobilization at the beginning of the Korean War — and Section 202c of the Federal Power Act, which allows the energy secretary to issue emergency orders during energy shortages.

The DOE memo said the retirements threaten the electric supplies for the nation’s military bases, citing a 2008 Defense Science Board report that noted virtually all of the electricity supplying the nation’s more than 500 military installations is generated outside the facilities. “Backup power at military installations is based on assumptions of a more resilient grid than exists and much shorter outages than may occur and is not sized to accommodate new homeland defense missions,” the report said.

At the time, the bases’ backup power was almost entirely diesel generators. Since then, the Defense Department has begun investing in microgrids and solar generation to allow their critical operations to continue operating during grid outages.

Preview?

Attorneys general from nine states and D.C. offered a preview of legal arguments against the DOE plan in challenging FirstEnergy Solutions’ March 29 request to invoke 202c to prevent retirements of its coal and nuclear generation in PJM.

In a May 9 letter to Perry, attorneys general for Massachusetts, Connecticut, Illinois, Maryland, North Carolina, Oregon, Rhode Island, Virginia, Washington state and D.C. said 202c was never intended to rescue “inefficient generators.”

Perry testifying before the House Energy Subcommittee | © RTO Insider

“Section 202c explicitly authorizes the secretary to issue temporary orders only in wartime or other ‘emergency’ situations resulting from ‘sudden’ electricity demand spikes or supply shortages,” they wrote. “Though the Federal Power Act does not define the terms ‘emergency’ or ‘sudden,’ the plain meaning of these terms indicates that Congress intended Section 202c authority to be invoked rarely, in response to acute events that demand immediate response.”

DOE says it has deployed Section 202c on eight occasions, all in response to regional energy challenges. It has not previously been applied nationwide.

The department’s memo contends that “Congress contemplated the use of the provision not merely to react to actual disasters, but to act in a preventive manner. A variety of man-made and natural threat conditions require … a federal agency ready to do all that can be done in order to prevent a breakdown in electric supply.”

The AGs cited statements by FERC and PJM that potential plant closures do not pose an emergency. They also rejected a National Energy Technology Laboratory study cited by FirstEnergy that concluded PJM’s demand during the December 2017-January 2018 cold snap “could not have been met without coal.”

The study “mistakenly concludes that coal-fired generation was critical to reliability because coal-fired generation disproportionately increased during the cold snap,” the AGs said. The extreme cold caused a spike in natural gas prices, briefly making coal generators more competitive.

“That certain resources were dispatched is not evidence the system lacked (or will lack during future events) other resources that could have been called upon instead to meet market demand and maintain reliability,” the AGs said. “PJM has more than enough capacity to meet demand, even in extreme weather.”

FAST Act

In addition to the DPA and FPA, the memo cites a third law as apparent authority, the 2015 Fixing America’s Surface Transportation Act (FAST) Act, which amends the FPA to authorize DOE to order emergency measures to protect “defense critical electric infrastructure” following a presidential declaration of an imminent grid security emergency.

Peskoe | © RTO Insider

“Citing these three laws implicitly concedes that there is no single law that provides DOE with the authority to do what it wants to do,” Ari Peskoe, director of the Electricity Initiative at Harvard Law School’s Environmental & Energy Law Program, said in a podcast last week. “DOE’s argument is that the whole is greater than the sum of its parts.”

Peskoe said there are three paths opponents could take to attempt to block the bailouts, including a federal court suit to overturn the eventual DOE order and FERC complaints challenging individual wholesale contracts compensating the at-risk plants as not just and reasonable. “And separately you could also have more action at FERC arguing that these contracts are disrupting the larger market,” he added.

Prior 202c Invocations

DOE’s most recent invocations of 202c were limited to single generating plants and local reliability problems.

In December 2005, DOE granted the D.C. Public Service Commission’s request to order Mirant Corp. to continue running its Potomac River Generating Station despite its inability to meet EPA’s National Ambient Air Quality Standards, finding that the region otherwise faced a “reasonable possibility” of extended blackouts.

DOE noted that much of the district, including the FBI, State Department and other federal government agencies, were supplied only by the Mirant plant and two 230-kV lines connected to other generation. The loss of those sources also would threaten the city’s water treatment center, which would be forced to release untreated sewage into the Potomac River if it lost power for more than a day, the department said.

The order required Mirant to keep the plant operating at a low level that allowed a quick start-up if either of the lines were lost. “Mirant and its customers should agree to mutually satisfactory terms for any costs incurred by Mirant under this order,” the department said. “lf no agreement can be reached, just and reasonable terms shall be established by a supplemental order.”

Originally set to expire in 10 months, the order was twice extended for two months and once for five months. It was terminated on July 1, 2007, after the completion of new transmission.

Most recently, DOE in June 2016 granted PJM’s request to order Dominion Energy Virginia to continue running its coal-fired Yorktown Power Station for 90 days despite its violation of EPA’s Mercury and Air Toxics Standards. The department found that reliability in the Hampton Roads area of Virginia could otherwise be at risk during summer peaks.

PJM said it needed to keep the plant available because of delays in construction of the 500-kV Skiffes Creek transmission project, the subject of court fights because of the proximity of its James River crossing near historic sites.

DOE extended the 90-day order four times thereafter, most recently on June 8, 2018. That order expires on Sept. 9. PJM’s most recent extension request estimated the transmission project will be complete in August 2019 and that Yorktown will not be dispatched after May 2019.

What’s FERC’s Role?

The five FERC commissioners are due to testify Tuesday before the Senate Energy and Natural Resources Committee in a previously scheduled oversight hearing. But it is unclear how much they will say about the proposed bailouts.

FERC was given no advance notice of the Trump directive and had received no additional information on it as of last Tuesday, when Chairman Kevin McIntyre met with reporters after speaking at the Energy Information Administration’s Energy Conference. (See related story, FERC Blindsided by Half-Baked Trump Order.)

The draft memo had been prepared in advance of a June 1 meeting of the National Security Council, and DOE’s plan will be reviewed by the NSC’s Policy Coordinating Committees. FERC is not a principal in the process.

Tezak | ClearView Energy Partners

Although FERC has been excluded from policy deliberations thus far, the resilience docket the commission opened in January could play a role in any litigation, Christine Tezak of ClearView Energy Partners said in an analysis for clients Friday (AD18-7). FERC opened the docket after rejecting DOE’s Notice of Proposed Rulemaking calling for price supports for coal and nuclear plants with on-site fuel. (See FERC Rejects DOE Rule, Opens RTO ‘Resilience’ Inquiry.)

Evidence that FERC, RTOs and states are moving aggressively on resilience could undercut DOE’s legal standing, Tezak said. “We would expect the opponents of action … to reference the contents of this proceeding before FERC as evidence that the DOE’s conclusions regarding resiliency are misplaced or in error.”

If DOE’s order survives legal challenges, the FERC proceeding could provide a path forward after the two-year study, Tezak said. “We think there is the potential for the FERC’s resilience docket to provide information that could lead to DOE winding down if not ending altogether its potential market intervention.”

In addition, FERC will hear testimony at its annual technical conference on reliability July 31 to consider whether new NERC standards are needed to ensure “essential reliability services” (AD18-11). NERC has identified those services as including frequency and voltage support, ramping capability, operating reserves and reactive power. (See NERC Report Urges Preserving Coal, Nuke ‘Attributes’.)

Chatterjee, Glick Call for Mandatory PL Standards

In a perhaps unlikely pairing, Commissioners Neil Chatterjee, a coal-state Republican, and Richard Glick, a carbon-conscious Democrat, joined Monday in an apparent effort to reassert FERC’s role in the debate. In a joint op-ed, they called for mandatory reliability standards for natural gas pipelines like those FERC and NERC enforce on the grid.

They noted that the Transportation Security Administration, which has responsibility for securing natural gas, oil and hazardous liquid pipelines, relies on voluntary cybersecurity standards. “In May 2017, TSA confirmed that it had just six full-time employees” overseeing pipeline security, they wrote.

“Given the high stakes, Congress should vest responsibility for pipeline security with an agency that fully comprehends the energy sector and has sufficient resources to address this growing threat,” they continued. “The Department of Energy could be an appropriate choice: It is the sector-specific agency for energy security and recently created its own cybersecurity office.”

How Will it Affect Emissions?

Because the bailout would cover both coal and nuclear plants, there is disagreement on how it would affect carbon emissions.

As of March, according to EIA, 21.2 GW of coal generation and 6.2 GW of nuclear capacity were scheduled to retire through 2027. EIA’s list does not include FirstEnergy’s announcement in late March that it will close its Davis-Besse, Perry and Beaver Valley nuclear plants, which total about 3.9 GW, by 2021.

About 21.2 GW of coal generation and 10.1 GW of nuclear capacity are at risk of retirement through 2027 | FirstEnergy Solutions, Energy Information Administration Electric Power Monthly, March 2018

Bloomberg New Energy Finance said in a report last week that emissions might be lower than the status quo if at-risk nuclear plants are kept running. It said that although capacity payments would keep coal plants available for backup, they may not actually run more under the Trump plan. Thus, the nuclear plants “could displace millions of tons of carbon dioxide a year” from coal plants, analyst Will Nelson said.

coal and nuclear plant retirements trump rick perry

Sivaram | © RTO Insider

While nuclear plants have capacity factors of more than 90%, many at-risk coal plants operate less than 50% of the time.

But Varun Sivaram, fellow for science and technology at the Council on Foreign Relations, told Axios last week that freezing coal and nuclear generation at their 2017 levels — preventing them from the drops forecast by EIA — would mean coal-fired production would be 24% more than the additional nuclear generation in 2025. That would translate to between 0 and 5% higher emissions in 2025 relative to 2017, depending on the relative displacement of gas and renewables, he said.

How Will it Impact RTO Markets?

RTO officials told RTO Insider last week that, like FERC, they had received no information from DOE on the plan or when it might be finalized. (See More Questions than Answers for FERC, RTOs on Bailout.)

“We don’t know if it will be a week, two weeks or months” before DOE acts, said one RTO official.

Craig Glazer, PJM’s vice president of federal government policy, told the EIA conference last week that Trump’s directive will “probably complicate” his RTO’s struggle to deal with state nuclear subsidies. He said he fears a “half slave/half free” industry in which generators dependent on market revenues increasingly compete with those receiving cost-of-service payments or subsidies.

While RTO officials may not lead the legal challenges, their insistence that there is no emergency won’t help DOE’s defense. They point out that they have been successful in keeping plants running temporarily beyond their retirement dates when needed to prevent reliability problems. ISO-NE, for example, has asked FERC to waive its Tariff to keep Exelon’s Mystic generating station running to address fuel security concerns. (See Mystic Waiver Request Spurs Strong Opposition.)

Prest | Resources for the Future

Palmer | Resources for the Future

Brian C. Prest and Karen L. Palmer, fellows with nonpartisan think tank Resources for the Future, wrote last week about the questions raised by DOE’s proposed Strategic Electric Generation Reserve. Among them: the size of the reserve, how generators would be procured and whether those selected be permitted to participate in or return to the energy markets.

Although the DOE memo provided no details, the fellows looked to the strategic reserve Germany is considering as it continues its phase out of nuclear power. The country has retired more than half of its nuclear generation since 2008 while more than tripling its non-hydro renewable capacity. It now gets half its capacity from non-hydro renewables versus 27% coal and nuclear and 14% gas.

Germany’s reserve will be initially capped at 2 GW, about 2% of peak load, rising to as much as 5 GW (5%) after 2020. The reserve capacity will be procured through technology-neutral competitive auctions and open to demand response. The capacity would be used only as a last resort.

“It is not clear from the scant description in the memo how the SEGR would be procured, but the heavy-handed approach for the electricity purchase mandates suggests that competitive auctions are probably not under consideration,” they wrote. “It seems more likely that plants would be chosen in the same way that they would be chosen for the electricity purchase mandates — based on a federally determined list of ‘fuel-secure’ generators (best interpreted as coal and nuclear plants).”

They note that Germany plans to address concerns the reserve will discourage new capacity investment by prohibiting reserve generators from re-entering the market. “Unfortunately, DOE’s proposed order is specifically designed to send the message that government policy will find a way for unprofitable plants to return to the market, even calling its own order a ‘stop-gap measure.’”

How Much Will it Cost?

Because so many details about the administration’s plan are unknown, no one has produced an analysis of how much it will cost — including DOE itself. (See related story, Dems Hit Coal, Nuke Bailout at House Hearing.)

But some analysts produced estimates on the DOE NOPR rejected by FERC. It would have given cost-of-service payments to coal and nuclear plants in RTOs with capacity markets if they have 90 days of fuel on site.

ICF estimated the NOPR would cost ratepayers $1 billion to $4 billion per year between 2018 and 2030. The estimate was based on contracts for differences bringing money-losing generators to break even.

ICF caveated that the analysis might have underestimated the cost because it did not include recovery of and on capital. But it said the analysis also didn’t account for the likelihood that wholesale electricity and natural gas prices will be lower than they would have been had the plants retired.

Orvis | Energy Innovation Policy & Technology

Energy Innovation Policy & Technology, which supports policies reducing greenhouse gas emissions, said the NOPR would have cost from $311 million to $900 million annually in PJM, ISO-NE, NYISO and MISO alone. The low estimate represents the out-of-market payments needed to bring units with negative net cash flows up to zero. The upper limit adds capital recovery and a rate of return on undepreciated capital and future capital expenditures.

“There are, of course, important differences between the resilience NOPR and the 202c actions being discussed by the Trump administration, but our study is a good rough estimate of the cost to keep the same group of uneconomic plants online,” said Robbie Orvis, director of energy policy design for the group.

June 12, 2018

Competition, Cooperation and Costs the Talk at OSW Conference

By Michael Kuser

BOSTON — Competition among states to set the highest offshore wind energy targets and to secure supply chain jobs is gradually giving way to a regional cooperation, the head of the Bureau of Ocean Energy Management said last week.

OSW Conference Offshore Wind Energy BOEM — Cruickshank | © *RTO Insider*

“In our view, all of the federal leases, they don’t belong to any particular state, and we need to be thinking about how to manage those assets on a regional community basis,” acting BOEM Director Walter Cruickshank said at New Energy Update’s U.S. Offshore Wind Conference, held June 7-8.

“And we’re certainly seeing that already,” Cruickshank added. “We’ve seen projects that were leased off of one state getting agreements with neighboring states.”

He cited the collaborative development efforts of Massachusetts and Rhode Island, of “Virginia and the Carolinas, and obviously in the New York Bight, where there are a lot of states that have stakeholder interest.”

New Energy Update held their annual U.S. Offshore Wind conference last week in Boston. | © *RTO Insider*

In May, Vineyard Wind, a partnership between Avangrid Renewables and Copenhagen Infrastructure Partners, won a contract to supply Massachusetts with 800 MW of offshore wind energy. In the same solicitation, Rhode Island picked Deepwater Wind to build a 400-MW version of its Revolution Wind proposal. (See Mass., R.I. Pick 1,200 MW in Offshore Wind Bids.)

Picking up the Pace

Panelists at the conference also discussed ways to reduce costs and speed up permitting.

The Department of Energy’s 2015 Wind Vision report set a goal of deploying 86 GW of offshore wind by 2050. The U.S. would need to use about 4.2% of the total technical resource area to reach the goal, according to the National Renewable Energy Laboratory’s September 2016 Offshore Wind Energy Resource Assessment. The technical resource area includes areas of the Great Lakes and the Atlantic and Pacific coasts with wind speeds of at least 7 meters/second and water depths of less than 60 meters (Great Lakes) or 1,000 meters (the oceans).

The 11 BOEM leases issued so far could produce 20 GW by 2030 “based on the physical capacity of these leases,” said Tom Harries of Bloomberg New Energy Finance. The typical timeline from lease to operation is five to seven years.

Stephen Bull, senior vice president at Norway-based Equinor (formerly Statoil), said he’d like “to see BOEM interact more at the state level, to really try to fast-track or work quicker to get wind energy areas out there.” Conference chair Stephen Pike, CEO of the Massachusetts Clean Energy Center, a state agency in charge of offshore wind development, asked about having BOEM pre-permit the leases to speed up development, as is done in Europe.

“That’s not the way the federal government works,” said Cruickshank, explaining that the bureau has no funding for capital-intensive marine surveys.

Floating Turbines

Although BOEM’s leases to date have been off the Atlantic Coast, BOEM is also looking to the Pacific, which will require floating wind technology because of the much greater water depths, Cruickshank said.

“We’re cautiously optimistic we’ll be able to move ahead with some of those leases later this year.”

Daniel Simmons, principal deputy assistant secretary for DOE’s Office of Energy Efficiency and Renewable Energy, said improving floating platforms “is an important area for us just because so much of our wind resources offshore is in deep water.”

Walter Musial, manager of offshore wind at the National Renewable Energy Laboratory, who explored the levelized cost of energy for floating turbines, said about 58% of potential offshore wind areas are deeper than 60 meters.

“Floating obviously starts out a bit more expensive, but it’s a maturity thing, so fixed and floating turbine costs converge over time,” Musial said. “Actual costs are confidential — they don’t report them in the newspaper.”

Manufacturers need to see the market demand in order to develop optimized turbine systems for floating platforms, he said. “Up till now, every single deployment has been with a turbine that was actually designed for a fixed bottom system, so we’re sub-optimum,” he said.

But the industry is now moving beyond the floating prototype phase. “I’ve counted about 11 projects totaling 229 MW,” Musial said. “These are going in with some subsidies, but also with regular financing, and they’re going in all over the world.”

NREL wind analyst Garrett Barter agreed, saying the current design paradigm of offshore turbines “won’t give you a cost-competitive floating system.”

Engineering and design are just a fraction of the total cost for a floating wind turbine. Most of the costs are the operational expenses, logistics, assembly and installation, and financing, he said.

“So you really need a systems approach that can tackle all these complexities at the same time, and not just focus on the turbine itself,” Barter said. He recommended multidisciplinary analysis and optimization, which is “a tool and also a state of mind where you connect the whole power production process, the whole load path, the controls that sit in between those two, and the whole balance sheet over the lifecycle of the plant.”

He said the offshore industry may have to evolve into a structure like that of the aerospace industry, where a global supply chain serves a system owned by the prime contractor.

Driving Down Costs

Experts say it will take several years for the U.S. market to mature before it matches the separate cost curves for the established European market

“We think the transition happens around 3 to 4 GW of installed capacity, which should be in 2028 in the U.S., and the industry will move onto the established cost curve and really see price reductions,” Harries said. “The regulatory route gets simplified, and then gradually you build your experience and you move down this cost curve. Supply chains gain experience, and routes to market become very clear.”

Jonathan Cole, managing director of offshore for Avangrid parent Iberdrola’s renewable business, wants to see nearly that much capacity entering the pipeline each year.

“As soon as possible, get to a place where this market is being fed with 2 to 3 GW of new projects every year, which means you’ve got enough volume to support a local supply chain,” Cole said. “That’s when you’ll truly see cost reductions and the industrialization happening.”

Cole said that so far, they’ve been able to lower development costs through tax credits, which are now being phased out.

“We’re hoping that the downside of removing the tax credits is going to be more than compensated by the positive … making a more efficient and optimized installation,” he said.

Northeast Advantage

Vineyard Wind CEO Lars Thaaning Pedersen said tax credits are an important part of the price structure in Massachusetts, but “the benefits … these projects will bring to the southeast coast” of New England may be more important, such as avoiding the high cost of building transmission lines to bring hydropower from Canada.

The state “has taken a bold step already … and I’m confident that Massachusetts will be at the center of the industry,” Pedersen said.

Francis Slingsby, head of strategic partnerships at Orsted, congratulated Pedersen. Despite not winning the first round of the Massachusetts-Rhode Island solicitation, Slingsby said Orsted is committed to developing its Massachusetts lease areas, “which in our estimation are superb.”

“Wind speeds increase as you move farther north along the coast, which gives New England an innate advantage,” he added.

Massachusetts Energy Secretary Matthew Beaton referred to the previous day’s tour of the New Bedford Marine Commerce Terminal, which was built for the deployment of offshore wind, as evidence of the state’s chance to lead the industry.

“To see international companies come in with Massachusetts companies made me realize … this thing’s for real, this thing’s happening, and we have all the pieces that we need,” Beaton said. “Eight hundred megawatts is just the starting point.”

Bill White, MassCEC director of offshore wind development, said, “Growth in Massachusetts is really about … what it will cost to ratepayers.”

John B. Lavelle, head of offshore wind for GE Renewable Energy, said volume will be the biggest driver of cost reductions. Lavelle said GE will “compete in the U.S. with our 12-MW platform that we just announced.”

Operating costs will come down partially through “a lot of automation,” Lavelle said. “You don’t want to send people 15 miles off the coast if you don’t have to.”

NY, NJ, Md. Moving Forward

Elisabeth Treseder, senior regulatory adviser for Orsted, said New Jersey’s commitment in May to build 3,500 MW of offshore wind by 2030 — surpassing New York’s target of 2,400 MW — “provides a lot of certainty and reassurance” to the market. (See Gov. Signs NJ Nuke Subsidy, Renewables Bills.)

“We’re still waiting for the New Jersey Board of Public Utilities to finish its plan, which for us means focusing on the local supply chain and workforce development,” Treseder said. “New Jersey was very wise in passing a $100 million tax break for offshore wind manufacturing, which left them an additional pool [of incentives] for suppliers.”

Kenneth J. Sheehan, director of economic development and emerging technologies at the BPU, said the state is working to develop its master plan and its first solicitation.

Left to right: Kenneth J. Sheehan, NJBPU; Elisabeth Treseder, Ørsted; and Jim Lanard, Magellan Wind | © *RTO Insider*

“We are looking for suppliers, transmission, for all the factors that go into it, and the OREC [offshore wind renewable energy credit], the single price, up-front method of funding, takes all this into consideration,” Sheehan said.

Jim Lanard, CEO of Magellan Wind, asked Sheehan what his state’s position is regarding wind energy areas that could serve both New York and New Jersey.

“Half the New York Bight is in New Jersey, so we’re not practically upset about additional project development off our shore,” Sheehan said, referring to the Atlantic Coast region between Cape May, N.J., and Montauk Point on Long Island. “At the start, it’s every state for itself. … Everything could be supplied from New Jersey. And New York thinks the same of itself.”

Kevin Knobloch, president of transmission developer Anbaric’s New York Ocean Grid, said that particularly with New Jersey’s goal of 3,500 MW, there’s a sense of great urgency to get the first turbines in the water.

“We believe the wise approach is from the very first solicitations to separate generation from transmission, and open it up to competition,” Knobloch said. “In so doing, the state decision-makers still reserve the right to go with an offer that’s bidding on both attributes.”

OSW Conference Offshore Wind Energy — Harries | © *RTO Insider*

Doreen Harris, director of large-scale renewables at the New York State Energy Research and Development Authority, said the agency is also identifying new wind energy areas off New York City. There is a proceeding before state regulators now “to make the first utility-scale procurement later this year,” she said.

Christer Geijerstam, director of the Empire Wind project for Equinor, which bought the first New York lease in 2016, said that aside from preparing for a state bid, the company is “focused on project technical issues to reduce asset risks” prior to the hoped-for start of construction.

John Hartnett, business opportunity manager of U.S. offshore wind for Shell Wind Energy, said his company “had really jumped into the U.S. markets driven by the evidence of the northeast. Right now, we are investigating the upcoming lease opportunities, both in Massachusetts and New York, and are very hopeful to have site control in time to participate in the upcoming auctions.”

The Maryland Public Service Commission approved two offshore wind projects totaling 368 MW in May 2017, allowing the developers to receive ORECs. The projects are estimated to create 9,700 full time equivalent jobs and result in more than $2 billion of economic activity in Maryland, including $120 million of investments in port infrastructure and steel fabrication facilities.

Samuel Beirne, wind energy program manager for the Maryland Energy Administration, said that “most offshore wind developers have to contract through the state Public Service Commission [to obtain ORECs] … and most use a third-party consultant to help them.”

Aileen Kenney, senior vice president of development for Deepwater Wind, said the company’s 120-MW Skipjack project off Maryland will start construction in 2021 and go online the following year.

“Right now we’re mapping all the seafloor, doing bathymetry analysis,” Kenney said.

Production Tax Credit

According to DOE, the federal renewable electricity production tax credit is an inflation-adjusted 1.9 cent/kWh tax credit for wind for the 2017 calendar year. The credit lasts 10 years after the date the facility is placed in service.

The tax credit is phased down for wind facilities as a percentage reduction: for wind facilities beginning construction in 2017, the PTC amount is reduced by 20%; for 2018, 40%; and for 2019, 60%.

June 12, 2018

FERC OKs Change to SPP ‘Net Benefits’ Test for DR

FERC last week approved SPP’s May 2016 proposal to change how it measures the net benefits of demand response under Order 745 (ER12-1179).

FERC Order 745 Net Benefits Demand Response — Inside SPP’s control room | *SPP*

The 2011 order requires grid operators to pay DR resources full LMPs when they are able to reduce demand and their dispatch is more cost-effective than generation, as determined by a net benefits test.

SPP’s May 2016 compliance filing came in response to an April 2014 FERC order requiring the RTO to re-evaluate its net benefits test methodology using Integrated Marketplace data. The commission also asked SPP to propose any necessary changes to make its methodology compliant with Order 745 and to re-evaluate the appropriateness of its systemwide DR cost allocation mechanism.

The RTO proposed adjusting its net benefits test to use all available offer data and include non-peak hour data in the construction of supply curves. It said it would first average supply curves and then smooth the resulting average curve when performing the net benefits test.

“We agree with SPP that these two design changes to SPP’s net benefits test methodology are appropriate given the greater availability of offer data in the Integrated Marketplace,” the commission said. It ordered SPP to file Tariff revisions by July 5 implementing the two changes.

FERC also accepted SPP’s explanation that it did not need to adjust its DR cost allocation provisions, given there had not been any load-reduction activity in its footprint.

— Tom Kleckner

June 12, 2018

Troubled Waters for Powerex in EIM

By Robert Mullin

PORTLAND, Ore. — Two months after making a smooth integration into the Western Energy Imbalance Market, Canada-based Powerex now finds itself navigating a turbulent relationship with market rules the company says undercut the value of its hydroelectric resources, company officials said last week.

At issue for Powerex is the frequency with which transmission constraints at the U.S.-Canada border trigger CAISO’s local market power mitigation (LMPM) process in the EIM, which mandates use of default energy bids (DEBs) to settle transactions. Inflexibility in the formulas underpinning the DEBs often leave Powerex market operations out of the money, the company says.

CAISO EIM Powerex hydro — Spires | © *RTO Insider*

“The LMPM processes and the DEB options are not workable for Powerex or for external hydro more generally,” Powerex Director of Power Jeff Spires said during a presentation at a June 6 meeting of the EIM Regional Issues Forum meeting at Bonneville Power Administration offices.

Powerex, which markets surplus power for the government-owned BC Hydro utility, began transacting in the EIM on April 4. As part of its membership, Powerex has volunteered about 300 MW of its transfer capacity into the market, half of which links British Columbia with the Puget Sound Energy balancing authority area (BAA) near Seattle. The other half allows transfers into CAISO via the Malin delivery point on the California-Oregon Intertie.

“We participate with large-scale hydro that’s very fast-ramping,” Mike Goodenough, Powerex trading manager, told the forum. “Often times we’re in a ‘buy’ mode, and particularly when the market is in oversupply, we’re buying, and the transmission can become constrained because we ramp so fast during the market power mitigation market run [that] the ties fill. And at that point, there’s a constraint and market power [mitigation] kicks in. The default bids then kick in and override all of our bids and offers.”

DEB Options ‘Formulaic’

The problem in those instances, Goodenough said, is that the EIM’s DEB options are “more or less formulaic” and “often very wrong” with respect to Powerex’s opportunity costs during a trading interval.

The result is “very frequent mitigation” that forces Powerex to sell below its opportunity costs when it intends to be purchasing in the market to take advantage of arbitrage, Goodenough said.

During these periods, Powerex’s traders seek to raise their sell offers upward to avoid sales but are prevented from doing so when mitigation kicks in, defaulting the market to rely on DEBs.

“And because the default bids are wrong, where we would be a buyer, we are now in the dispatch run as a seller,” he said. “And so, there’s obviously two problems there. One is, we’re now selling into a market in which there might already be in oversupply. But more importantly for us, we’re now depleting energy-limited resources at the wrong time.”

In an April 30 presentation to a CAISO workshop on broader DEB issues, Powerex described the shortcomings of each default bid option available to EIM market participants heavily reliant on hydro assets:

The “variable cost” option, based on heat rates, fuel price and greenhouse gas costs, is “not relevant” for hydro resources that are more driven by opportunity costs than variable production costs.
The “backward-looking” LMP option — based on the on the lowest 25th percentile of LMPs at which a resource has been dispatched during the previous 90 days — is “not workable” for hydro resources whose opportunity costs “are driven by current and expected future conditions.”
The “negotiated rate” option, in which a formula is negotiated between a resource’s scheduling coordinator and CAISO and its Department of Market Monitoring, is “theoretically workable” for all resources but “not workable in practice” for hydro resources outside the CAISO BAA. This option requires the ability to determine a methodology to estimate expected marginal costs, “which are complex, dynamic, and involve both objective and subjective factors,” Powerex said.

“You can’t precisely estimate costs for hydro,” Spires told the forum. “External [to the CAISO BAA] hydro in particular has multiple bilateral opportunities. We have a myriad of constraints within the BC network,” including seasonal monthly, weekly and daily storage requirements, as well as recreational constraints.

“There’s so many different things and they can change at the drop of a hat and you need to be able to respond to that, and so we really support flexibility in determining what your marginal opportunity costs are,” Spires said. He said the flexibility is required to avoid “forced sales.”

Spires said that the EIM’s LMPM process functions as if the supplier conduct threshold for triggering mitigation is zero, meaning that “as soon as your bid or offer price is even a penny above the reference price, then you’re subject to potential mitigation if the transmission is constrained.”

“It goes beyond the commercial impact — it’s an operation impact as well,” Spires said. “And it’s a loss of control of being able to decide what to do with your resources in light of the information that you have at the time.”

Unlike other EIM members, Powerex functions only as a marketing operation and not as a balancing authority or load-serving entity, which means it has no ratepayers exposed to EIM prices.

Thus, the company says its import transfer path into British Columbia is used primarily for “economic displacement” (importing low-priced power to displace use of internal generation) and doesn’t serve any retail customers. In its April 30 presentation, the company questioned whether it was appropriate to apply LMPM to transfer paths where “there is no potential for market power.”

Spires said the situation is discouraging Powerex’s participation in the EIM.

“It’s frankly less attractive than the existing real-time market — the intertie bidding framework where we don’t face these issues, [and] particularly for us, because we have transmission access to the CAISO and so we’ve got the opportunity to deliver a clean supply into that market,” he said. “And so the EIM is a step backwards from that perspective.”

Spires concluded his presentation by expressing appreciation for CAISO’s support in transitioning Powerex into the EIM, but he also urged the ISO to address the company’s dilemma soon.

“We think that it is important to others, and we’re looking forward to working on these issues, but we need a resolution quickly.”

Interim Solution?

In April, CAISO asked FERC to approve a Tariff waiver to alleviate the impact of LMPM on Powerex’s operations by reducing the number of intervals for which mitigation applies after being triggered (ER13-1889).

“The interim solution consists of an automated process by which Powerex’s EIM transfers will be restricted only during intervals in which this condition [producing forced sales] occurs, as well as limiting mitigation of Powerex’s aggregated participating resource to the market interval in which the mitigation of that resource is triggered,” CAISO said in its filing.

The ISO said the interim solution “will apply solely to Powerex’s aggregated participating resource operating under the unique Canadian EIM entity arrangements.”

But while the potential Tariff waiver would partially alleviate the LMPM issue for Powerex, the company has noted it would not address the company’s underlying concerns about the DEB calculation options or the fact that its sales prices would be mitigated to uneconomic levels when LMPM is triggered.

During the April 30 workshop, CAISO Vice President for Market Quality and Renewable Integration Mark Rothleder acknowledged “there is a gap” between what some stakeholders “feel their ultimate opportunity costs are and what they believe a calculated DEB under the existing mechanisms can achieve.”

“This may be the fundamental issue in terms of continuing the EIM and the success of the EIM, so we have to get this right,” Rothleder said, adding that the ISO must receive comments from stakeholders before kicking off an initiative to address the DEB issue.

While time might be of the essence for Powerex, CAISO told RTO Insider on Monday that “no time frame has been set for this miscellaneous stakeholder process as of this time, although we do plan to have a second workshop in July to further discuss the concerns and some ideas for addressing them.”

June 12, 2018

SPP Briefs: Week Ending June 8, 2018

SPP said last week it is accepting applications for industry experts to serve on a fourth independent panel to review Order 1000 transmission proposals in 2019.

The RTO forms the pool each year to manage competitive projects. A panel composed of experts from the pool will review, rank and score proposals for competitive projects approved for construction by the Board of Directors.

Interested candidates must have expertise in at least one of the following transmission-related areas:

Engineering design
Project management and construction
Operations
Rate design and analysis
Finance

Applications will be accepted through Aug. 31. Panelists will be selected based on a recommendation by SPP’s Oversight Committee and approved by the board later this year. Those serving on the panel will be considered contractors and will be compensated through a monthly retainer and hourly rate.

More information can be found on SPP’s website. Interested parties may also contact regulatory analyst Aaron Shipley.

Previous panels have awarded a single transmission project in Kansas, which was eventually canceled because of falling load projections. (See SPP Cancels First Competitive Tx Project, Citing Falling Demand Projections.)

MISO Racks up $1.97M in April M2M Charges

For the ninth straight month and 17th of the last 19, SPP amassed market-to-market (M2M) payments in its favor from MISO during April.

SPP staff said during its Seams Steering Committee meeting last week that MISO incurred $1.97 million in charges, increasing its total payments to SPP to $53.3 million since the two neighbors began the process in March 2015.

The main cause of charges in April was the Nebraska City temporary flowgate in Omaha Public Power District’s control zone. The constraint was binding for only 30 hours during April but racked up more than $717,000 in charges because of area outages, combined with lower wind generation and high south-to-north flows.

SPP’s Nashua-Hawthorn permanent flowgate in Kansas was binding for 142 hours and accumulated more than $427,000 in M2M charges.

The committee met June 6 at Southwestern Public Service’s offices in Amarillo, Texas.

— Tom Kleckner

June 12, 2018

Solar Inverter Problem Leads CAISO to Boost Reserves

By Jason Fordney

CAISO will make permanent a once-temporary practice of boosting its power reserves to account for utility-scale solar tripping offline because of an inverters problem, something NERC has identified as a major reliability issue.

When solar generation is at its peak, CAISO will set the operating reserve target at either 15% of the total solar production forecast or the maximum NERC/Western Electricity Coordination Council requirement, whichever is greater.

The ISO has worked with solar operators to reprogram inverters since last year, CAISO Shift Supervisor John Phipps said Monday at a Market Performance and Planning Forum. Some of the inverters began working properly after reprogramming, but others are hard-wired and still subject to tripping. Phipps said ~~that~~ 2,700-2,800 MW of generation across the whole ISO system cannot be reprogrammed.

“They are not in any one regional area;, they are spread out across all the plants in California,” Phipps said during a pres e ntation, adding that the issue is not affecting behind-the-meter or storage resources.

The inverters, which convert photovoltaic DC output to utility frequency AC, sometimes trip offline to protect the systems during voltage fluctuations. CAISO began procuring additional reserves a year ago, after the problem occurred in August 2016 because the Blue Cut fire in Cajon Pass caused transmission line faults and disconnected 1,200 MW of solar. (See CAISO B o osts Reserves After August Event Report.)

CAISO CEO Steve Berberich last month cautioned the ISO’s Board of Governors about the seriousness of the problem, which caused the loss of 860 MW of solar resources on April 20. (See CAISO Board Approves Forecast Error M e asures.)

The inverter problems have so far triggered two NERC alerts, one on June 20, 2017, and the other on Ma y 1 of this year. NERC said the problem could also affect non-bulk power systems and recommended all operators follow certain recommendations spelled out in the more recent alert.

“While this NERC alert focuses on solar PV, we encourage similar activities for other inverter-based resources such as, but not limited to, battery energy storage and wind resources,” the agency said in the May 1 alert.

Ancillary Service Scarcity Increases

CAISO has seen an increase in ancillary service scarcity events in the real-time market, Director of Market Analysis and Forecasting Guillermo Bautista Alderete told the forum. He said ~~that~~ while the number of incidents has increased, the magnitudes are small, with about 75% of the scarcities at fewer than 10 MW. The increased incidents stem from a confluence of factors and changes in the market, he said, including the solar operating reserve requirement.

Most recently, CAISO issued three notices of ancillary service scarcity events for May 3-6, May 15, and May 23-28, nearly all of which were associated with regulation up service and mostly in the SP26_EXP region in Southern California. In 2018, 46% of the scarcities happened in SP26_EXP, 35% in NP26_EXP and 19% in CAISO_EXP.

CAISO pays an ancillary services scarcity price when it is unable to procure the target quantity of one or more ancillary services in the integrated forward market or real-time market runs. About 52% of the scarcities are due to limits in generator telemetry, which is the process whereby a generator supplies the ISO with real-time data. Mismatches between telemetry and real-time needs require the ISO to procure additional capacity in the real-time market. About 33% are due to generator outages and re-rates, and 15% categorized are as “other.”

CAISO’s Market Monitor in its 2017 State of the Market report noted that scarcity events in the real-time market “increased significantly” from 26 in 2016 to 54 in 2017.

June 10, 2018

MISO Stakeholders to Rank Market Improvement Ideas

By Amanda Durish Cook

CARMEL, Ind. — Over the next month, MISO stakeholders will rank 14 market improvements the RTO might undertake in 2019.

Stakeholders have until July 12 to take MISO’s Market Roadmap candidate ranking survey and organize eight new and six existing improvements by priority. The survey was announced during a June 7 workshop.

In addition to ranking the eight new submissions approved this spring for consideration by the Steering Committee, stakeholders will also consider six currently active initiatives that have already been discussed in stakeholder meetings. (See Steering Committee Advances MISO Market Improvement Ideas.)

The active items under consideration include:

Improving generator modeling so it can depict more combinations of combined cycle units;
Creating a short-term capacity reserve product available to solve capacity shortages within 30 minutes;
Developing a multiday market forecast;
Improving energy storage resource integration beyond what is required for FERC compliance;
Automating dynamic ratings for transmission lines that offer temperature-adjusted and short-term emergency ratings; and
Continuing to develop new market rules and requirements under MISO’s large resource availability and need effort. (See MISO Looks to Address Changing Resource Availability.)

MISO will review survey results at the August Market Subcommittee meeting, and then reconcile its preferred ranking with stakeholders’ prioritization to update a work plan for 2019 to 2023, said Lakisha Johnson, the RTO’s market strategy adviser.

The RTO has already issued a first draft of the roadmap based on internal rankings of the 14 proposals, designating its resource availability and need (RAN) effort, and plan to create a short-term capacity product as top priorities, followed by better modeling of combined cycle generators. Next on the list: creating a look-ahead dispatch tool, improved modeling of all generators and more comprehensive storage resource integration. The RTO ranked all other candidates as low importance.

This year’s ranking features only a partial list of roadmap ideas and doesn’t include improvements relegated to the “parking lot,” the lowest-ranked candidates that MISO and stakeholders predict will be useful sometime in the future. Parking lot items are reintroduced in the ranking for refreshed status every other year.

energy storage resource integration miso pjm market roadmap — Adams | © *RTO Insider*

“Each year, we alternate between doing a fully exhaustive ranking of the parking lot versus only focusing on active and new candidates,” explained MISO Senior Manager of Market Strategy Mia Adams.

However, this year, MISO moved the suggestion for financial incentives for primary frequency response from the parking lot into the Market Roadmap because Indianapolis Power & Light submitted a new version of the suggestion.

Some stakeholders wondered if some improvements should be combined with others.

“There’s some concern if you make something of a Frankenstein roadmap product,” Adams said, adding that MISO may be open to bundling market improvements into portfolios when it makes sense.

Customized Energy Solutions’ Ted Kuhn said he thought the roadmap was meant for more in-depth market improvements than some of the new ones submitted this year, singling out Independent Market Monitor David Patton’s new recommendation to remove transmission charges from coordinated transmission service with PJM.

Patton said the coordinated transactions with PJM are rarely used, and the product has “failed” because MISO levies charges when an offer is made in addition to when an offer is struck.

But Kuhn said the Monitor’s suggestion could be completed “in a weekend” and questioned its consideration in the roadmap.

MISO Executive Director of Market Operations Jeff Bladen said Market Roadmap items represent “a variety of dimensions” and said stakeholders should come with suggestions on which products could be fast-tracked.

Northern Indiana Public Service Co.’s Bill SeDoris said one parking lot item should be considered sooner than next year — creating a compensation process for energy delivered during a system restoration event, an idea currently on hold. The item is timely and fits well into current discussions around resilience, SeDoris said. He added that the issue had been discussed recently in closed session discussions of the Reliable Operations Working Group.

Patton cautioned against focusing too much on the resilience “buzz word” when deciding which improvements to undertake.

SeDoris responded that MISO might appear remiss for not having discussed restoration energy compensation the next time it goes before FERC to discuss resilience. He said he would bring the issue to the Steering Committee’s next meeting in the hopes of reigniting interest in creating a compensation mechanism.

June 10, 2018

Land Rights a Challenge to Mexico Tx Developers

By Tom Kleckner

MEXICO CITY — Bob Smith has enjoyed a long career in transmission planning and development, much of it in the American West where he said federal lands can create “unique problems” for building electric infrastructure.

As vice president of transmission, planning and development for TransCanyon, Smith is responsible for conceptualizing and planning transmission projects for the joint venture between Berkshire Hathaway Energy and Pinnacle West Capital.

BHE is Warren Buffett’s energy holding company that includes PacifiCorp and NV Energy. Pinnacle West’s assets include Arizona Public Service. Together, they offer $90 billion worth of “leverage” to TransCanyon.

Smith told a Gulf Coast Power Association breakfast audience last week that “there’s a clear need for transmission infrastructure” in Mexico, and that the country is “fertile ground for these opportunities.”

So why is TransCanyon going to “watch the process and see what happens” for the time being?

Two words, say veterans of the emerging Mexican market: land rights.

“I’ve gotten the sense it’s every bit as difficult here as it is in the United States,” Smith said during the June 6 breakfast, the seventh in a series. “I get the sense there’s a real value of the long-term commitment to the land and cultural identity.”

Stations of the Cross

Just ask Energia Veleta’s Mannti Cummins, who is working to develop a 50-MW wind farm in Baja California Sur. He filed a social impact study, one of several necessary requirements before construction can begin, with Mexico’s Ministry of Energy (SENER) in July 2016. He received a response back last week.

However, first Cummins had to meet with a SENER representative housed in the ministry’s training facility, a dated, one-story, cement building located in a working-class part of Mexico City. Cummins was told his study was in order, but that he would a receive an electronic copy of SENER’s “opinion letter” later. The document, indicating the Office of Social Impact Studies had the “necessary and sufficient information” to do its own evaluation, arrived in Cummins’ email at 1:10 a.m. He then had to return to the SENER office later that morning to sign a document acknowledging he had received the PDF.

Electronic signatures are not considered official in Mexico, Cummins said.

“They want original, wet signatures. The most mundane business in the U.S. becomes an administrative stations of the cross here in Mexico,” said Cummins, a practicing Catholic.

Fortunately for Cummins, the proposed wind farm is in a desolate area of the state, near the oil-fired generators “that keep the beer cold in Cabo.” He only had two landowners to deal with, and none of the federal lands, social property, conservation areas and indigenous territory that other developers will face. Still, it took a team of six students working 24/7 for six weeks under their former professor to produce baseline studies, conduct interviews and draft the report.

“It would take anyone else six months,” said Cummins, who was facing an investor’s deadline. “And this was for 50,000 acres and two landowners.”

Legacy of Revolution

Mexico Transmission Planning Land Rights — Robinson | © *RTO Insider*

Sebastian Robinson, director general of Punto Focal, a surveying firm that specializes in setting real estate boundaries, says 51% of the country now consists of social property called ejidos, a result of the Mexican Revolution that dragged on from 1910 to 1940. When you discount the urban areas, he said, that percentage jumps into the 60s.

“The problem is, ownership has become muddled,” Robinson said.

Land ownership became an issue in the 1890s, when 20% of the country was owned by foreign interests and rich landowners. By 1910, half the country’s rural population worked on huge estates essentially as slaves, and the pent-up frustration was one of the primary causes of the revolution.

It wasn’t until socialist Lazaro Cardenas was elected president in 1934 that much of the ensuing violence subsided. Cardenas instituted the practice of ejidos, in which peasants within a community were given sub-parcels of former estates or national land — some as large as 120,000 acres — but the land was not necessarily registered, Robinson said. President Carlos Salinas eventually ended the practice in 1992.

Many of the ejidos’ original owners have long since died without transferring the titles, or they have moved into the cities to escape rural poverty. “With maybe 90% of the ejidos, there’s no chain of title,” Robinson said.

And while the government maintains a public registry of social land, Robinson said there’s no legal inventory of land ownership. The problem is magnified by the lack of accurate surveys.

Robinson and Cummins bring all this up in pointing to the potential difficulties facing the first two competitive transmission projects currently out for bids by Mexico’s state-run utility, the Federal Electricity Commission (CFE). Mexico’s energy reform of 2014 opened up the transmission system to private contractors, partly because CFE keeps its retail rates artificially low for political purposes, and it can afford to do little more than keep the lights on, Cummins said.

One of the projects is a $1.2 billion, 870-mile, 500-kV connection between Mexicali in Baja California and Hermosillo, Sonora, in northwestern Mexico. The second is the $1.7 billion Oaxaca project, more than 1,000 miles of 500-kV line between Mexico City and Veracruz, home to the country’s only nuclear plant. Technical bids on the first line are due June 15, and the Oaxaca bids are due in July, but a requirement of HVDC experience will likely limit the field.

Robinson said CFE already owns 89% of the Oaxaca project’s right of way, but that still leaves about 100 miles of line where ownership will have to be determined and dealt with. “That’s a lot of problems,” he said.

Both projects will be built under a build-operate-transfer (BOT) model, in which private companies will build the infrastructure, operate and maintain the system while recovering rates, and then transfer all the rights, licenses, permits, authorizations and property to CFE.

“CFE used to own it all,” Cummins said. “Now, it just administers the network.”

Watch and Wait

Still, developers say Mexico is too big of a market to ignore. SENER says the country’s generating capacity has doubled to more than 73 GW since 2000, and load growth and the retirement of aging, inefficient plants will require another estimated 50 GW of generation over the next 15 years. Mexico hopes to add $10 billion worth of transmission infrastructure in the coming years, including the two competitive projects.

Smith pointed to Mexico’s load growth, broad support for renewable energy and “mature and competent” planning processes as reasons to get involved in the market.

To be fair, Smith said TransCanyon was too late to bid on the Oaxaca project. The company did look at the Hermosillo-Mexicali project, he said, but decided to “monitor progress” of the initial offers “to learn the best way to engage.”

“We decided at this point, between the risk and lack of experience [in Mexico], we decided it wasn’t a wise thing to do,” he said. “We’ll try to learn lessons on best way going forward. There are some tremendous opportunities here. It’s early, very early in the process, but it’ll be interesting to see how it goes.”

June 10, 2018

FERC OKs Reliability Standard on Fault Protections

By Rich Heidorn Jr.

FERC last week gave final approval to NERC reliability standards on training requirements and the coordination of protection systems to detect and isolate faults (Order 847, RM16-22).

Standard PER-006-1 (Specific Training for Personnel) sets training requirements for real-time operations personnel to ensure they understand the purpose and limitations of protection systems schemes. It also adds more precise and auditable requirements, FERC said.

FERC Reliability Standards Fault Protections — | © *RTO Insider*

PRC-027-1 (Coordination of Protection Systems for Performance During Faults) seeks to ensure protection systems operate in the intended sequence. It requires applicable entities to perform a protection system coordination study to determine whether the systems are operating in the proper sequence during faults or compare present fault current values to an established fault current baseline. In the latter case, a coordination study would be required only if there is a 15% or greater deviation in fault current values. The reviews are required every six years.

The commission’s June 7 order also approved new and revised definitions for three terms: protection system coordination study, operational planning analysis and real-time assessment.

FERC, however, rejected a proposal in its Notice of Proposed Rulemaking to modify PRC-027-1 to require an initial protection system coordination study as a baseline, bowing to complaints by NERC and others.

NERC said that although the requirement could help reduce misoperations caused by a lack of coordination, it would be costly and burdensome. The reliability organization said it “expects that many entities will choose to do a full protection system coordination study … for their more impactful [bulk electric system] elements” and that “it is highly likely that the overwhelming majority of entities have already conducted coordination studies for their protection systems.”

FERC said it agreed that applicable entities will conduct studies on their significant facilities even without the requirement.

“We recognize the concern that were the NOPR directive adopted, applicable entities could be required to rerun protection system coordination studies for the sole purpose of generating compliance documentation, even if such entities already performed protection system coordination studies that remain valid but lack documentation to substantiate compliance,” the commission said.

June 10, 2018

Court Backs FERC Reversal on PJM Tx Upgrade

By Rich Heidorn Jr.

The D.C. Circuit Court of Appeals on Friday backed FERC in its revised interpretation of a PJM Tariff provision governing responsibility for transmission upgrades, turning aside a challenge by the owner of a power plant in Marcus Hook, Pa. (ESI Energy v. FERC, 16-1342).

At issue was whether LS Power Associates, the parent of West Deptford Energy, should be liable for transmission upgrades ordered before the developer entered PJM’s interconnection queue. In 2014, the court vacated FERC’s order ruling the company was liable, calling the commission’s decision “the very essence of unreasoned and arbitrary decision-making.” (See Appeals Court Scolds FERC over West Deptford Interconnection Dispute.)

West Deptford (N.J.) energy plant under construction| *MJ Electric*

West Deptford submitted its interconnection request on July 31, 2006, and was later informed it would be assessed $10 million for improvements PJM ordered as a result of two previous projects, FPL Energy Marcus Hook and Liberty Electric.

Tariff Change

Under section 37.7 of the PJM Tariff then in effect, the RTO could seek reimbursement for a previously constructed network upgrade if the new proposed project used the added capacity created by the project or would have required it itself. The reimbursement request only applied if the cost of the upgrade was at least $10 million and it was placed in service no more than five years before the interconnection customer’s queue closing date.

If section 37.7 controlled, West Deptford would have been required to reimburse Marcus Hook and Liberty Electric for the upgrade. (Ninety percent of the upgrade’s cost had initially been assigned to Marcus Hook.)

In 2008, however, while West Deptford’s interconnection request was pending, PJM won approval for an amendment changing the assignment of responsibility for prior upgrades. Section 219 of the revised Tariff allowed PJM to seek reimbursement for previously constructed upgrades for only five years “from the execution date of the interconnection service agreement for the project that initially necessitated” the upgrade.

FERC initially ruled that West Deptford must pay, concluding that the 2006 rules applied. But the court said FERC’s ruling “provided no reasoned explanation for how its decision comports with statutory direction, prior agency practice or the purposes of the filed rate doctrine.”

FERC Reversal

In response to the remand, FERC in August 2016 reversed its ruling, relieving West Deptford of the reimbursement obligation (ER11-4073). FERC said it based its decision on the “significant skepticism” the D.C. Circuit expressed in the remand order and the “numerous shortcomings” the court identified in the commission’s analysis.

Marcus Hook appealed, saying the old rules should apply to West Deptford and challenging FERC’s interpretation of the five-year trigger under the new rules. (Florida Power & Light subsidiary ESI Energy was later substituted for Marcus Hook as petitioner.)

In siding with FERC, the court said the commission “directly and adequately addressed” Marcus Hook’s challenges to the determination that section 219 applied.

FERC was required to provide a “reasoned explanation” of how applying section 219 comported with the Federal Power Act and commission precedent, the court noted. “Unlike its prior decision, the commission’s decision on remand did both,” it said.

5-Year Trigger

Although section 219 did not specify what action was required within the five-year window to trigger cost responsibility, FERC said the most reasonable interpretation was that the “end date” was that on which West Deptford signed its interconnection agreement.

Marcus Hook argued that section 219 made an interconnection customer liable for an upgrade that entered service during the five years preceding the customer’s queue entry. It said the dispositive date should be either when West Deptford submitted its interconnection request (July 31, 2006) or when PJM determined that the upgrade was required for its interconnection (November 2006).

“Although Marcus Hook’s suggested interpretation is a possible reading of the Tariff provision, it is no more reasonable than the one the commission put forward,” the court ruled. “Accordingly, we find that the commission did not err in its interpretation of section 219 of the revised Tariff.”