Page 1472 – RTO Insider

March 8, 2016

SPP: FERC not Budging on non-Order 1000 Seams Projects

FERC staff is hesitant to entertain consideration of a regional cost allocation methodology for seams projects approved outside of an Order 1000 process, SPP staff told the Seams Steering Committee last week.

In recent discussions, said Brett Hooton, SPP’s senior interregional coordinator, FERC staff seemed concerned about ensuring Order 1000 will be the only process “under which a planning region will include a regional cost allocation in [its] tariff for seams projects.”

FERC Rejects SPP Proposal for Seams Transmission Projects.)

Some SPP stakeholders expressed concern with FERC’s position, saying it hurts the RTO’s ability to approve a large number of potential projects not eligible under Order 1000.

SPP staff noted that no interregional projects have been approved anywhere in the country under Order 1000.

Meetings This Week

The committee also previewed two meetings with MISO this week related to the joint operating agreement and interregional planning.

The JOA stakeholder meeting Tuesday will focus on ongoing operational issues between the regions and potential improvements to the market-to-market process.

At the March 9 Interregional Planning Stakeholder Advisory Committee meeting, stakeholders will discuss high-value M2M flowgates, the results of the RTOs’ Clean Power Plan studies and whether the RTOs should conduct a joint transmission study this year.

— Tom Kleckner

March 8, 2016

New England Stakeholders Debate Solar Subsidies

By William Opalka

NEWTON, Mass. — More than 150 people attended the Northeast Energy and Commerce Association’s 13th Conference on Renewable Energy Thursday. Here are some highlights of the speakers’ comments.

Timothy Rougan, National Grid’s director of energy and environmental policy, and Cynthia Arcate, CEO of PowerOptions, said it’s time for Massachusetts to reconsider its generous solar subsidies.

“What people are getting paid — whether it was $6 a watt on their house, or $1.50 a watt on a 5-MW solar farm — it’s much more than in surrounding states,” Roughan said. “There’s only so much money in the pie and we need to make intelligent decisions on where it needs to go.”

“The incentives in Massachusetts have done a phenomenal job in jump-starting the industry, but we’re beyond the beta stage,” said Arcate, whose company helps more than 500 nonprofits with $200 million in annual energy spending maximize their buying power. “I believe the incentives are too rich and we need to reconfigure it somehow.”

Michael Cuzzi, senior vice president of VOX Global, a strategic communications firm, said the challenges of siting new infrastructure are especially acute in New England, “where our traditions of local control remain very strong and where resistance to change seems bred into our DNA.”

“Questions about cost-competitiveness and subsidies still linger [and have an] ability to unite strange political bedfellows, with opposition to projects coming from the environmental left and the fiscally conservative and libertarian right. So for the politicians in the host communities, there is no political safe space.”

John Fernandes, director of policy and market development for Renewable Energy Systems’ North American unit, which has built or has under construction more than 80 storage and renewable energy projects, said one benefit of storage is its flexibility. “I can do a lot more with a storage plant than I can do with 40 miles of transmission. All I can do with 40 miles of transmission is move electrons,” he said. “Not to oversimplify it, but I can pick up and move a storage plant a lot easier.”

Bryan Sanderson, senior vice president of Anbaric Transmission, made a pitch for the company’s proposed Vermont Green Line, which would deliver Canadian hydropower and New York wind power over a transmission line partly under Lake Champlain.

“We view transmission paired with wind and hydro as the most cost-effective way to deliver clean energy at large scale into the region,” he said.

March 8, 2016

IPPs Push 3-Year Forward Auction for MISO; Consumer Advocates Urge Caution

By Amanda Durish Cook

MISO stakeholders continued their debate over the RTO’s capacity market rules Monday with independent power producers saying the RTO should borrow elements from PJM and consumer advocates warning that the proposals were premature and could increase prices.

The discussion, which focused largely on Illinois’ Zone 4, came at a meeting of the Competitive Retail Solution Task Team.

NRG Energy, Noble American Energy Solutions and Mainline Energy called for a transition to a downward sloping demand curve from the current vertical curve, which critics say results in excessive price volatility.

Abraham Silverman, NRG Energy’s assistant general counsel for regulatory affairs, presented a proposal that also called for a mandatory three-year forward auction for retail choice zones in Illinois and Michigan.

The auctions would be optional in the rest of MISO, which depends on state-run integrated resource plans — although load-serving entities in those states would be required to demonstrate three years in advance that they have sufficient resources to meet their capacity needs through the auction, self-supply or bilateral transactions.

NRG’s proposal was based on a study it commissioned by The Brattle Group. Brattle’s study said MISO’s survey of LSEs’ capacity resources, conducted with the Organization of MISO States, “does not adequately ensure reliability.”

“Shortages for retail choice customers would affect the reliability of the whole system, including traditionally regulated states,” Brattle said.

Mainline Energy likewise advocated for procuring capacity three years in advance. “We’re not trying to recreate the markets, we’re trying to create a price signal here,” said Michael Borgatti, director of RTO services for Gabel Associates, who appeared on behalf of Mainline Energy.

Borgatti said competition could drive down prices and volatility. “Let’s be honest, in the last three years, we’ve seen capacity prices around $3 [per megawatt-day], we’ve seen $17 and we’ve seen $150,” he said.

Noble American Energy Solutions’ Roy Boston proposed a three-year auction and downward sloping demand curve modeled after PJM. MISO’s “short-term procurement auctions do not give potential entrants an opportunity to participate in the auction, which increases the potential for incumbent generators to exercise market power,” Boston said.

At a meeting of the task team last month, Exelon and Dynegy also proposed a move to a PJM-like construct. (See Dynegy, Exelon Propose PJM-Type Capacity Auction for MISO Zone 4.)

However, the Illinois Citizens Utility Board and AARP said MISO’s goal of filing proposed new rules with FERC by May 5 was premature.

“Presentations made to this working group have so far been nothing more than ways to increase capacity prices for existing generators,” said Bryan McDaniel of the CUB. “While generators give lip service to not making Zone 4 ‘an island,’ their proposals would make Zone 4 even more of an island.”

AARP staffer Bill Malcolm encouraged MISO to slow down, saying MISO’s “sufficient capacity” afforded the RTO time to thoroughly vet available auction options.

Susan Satter, public utilities counsel for the Illinois Attorney General’s Office, likewise said there was a “substantial surplus” of capacity in Zone 4 and there was no need to rush changes. She urged waiting on a long-term solution until the MISO-OMS survey is completed in July.

Satter’s office said presentations to the task team so far “have failed to provide data or analysis to show that the [Planning Resource Auction] as constructed will result in insufficient resources.”

“Generator desire for more revenue should not be the basis for radical changes in the PRA to increase capacity prices for Illinois,” the office said.

MISO officials again withheld comment on whether they favored any of the proposals.

Jeff Bladen, MISO’s executive director of market design, did offer one critique. “When you have three-year forward procurement, you have higher uncertainty about what’s going to happen three years into the future. What you have is a higher installed reserve margin to meet that one-day-in-10-year standard,” he said.

He also reminded stakeholders that the PRA isn’t meant to function as the primary mechanism for ensuring sufficient capacity.

Independent Market Monitor David Patton also questioned the advantages of abandoning MISO’s “prompt” auction, which procures capacity two months before the delivery year.

“I’m not sure the economic theories surrounding mandatory forward procurement have been robustly tested. We need to rigorously test the assumptions,” Patton said. “There’s not a lot of difference in prompt auctions and three-year forward auctions in how it motivates investments…The real question here is revenue.”

Patton did reiterate his support for a switch to a sloped demand curve.

March 8, 2016January 25, 2024

Storage, DR Dominate Talk at ERCOT Market Summit

By Tom Kleckner

AUSTIN, Texas — Energy storage, demand response and solar have a place alongside wind in the Texas market, speakers at Infocast’s ERCOT Market Summit said last week.

PTC Reductions will Challenge Wind

Susan Williams Sloan, the American Wind Energy Association’s vice president for state policy, said the extension of the wind production tax credit provides “five years of certainty. It’s what we have been looking for to compete in this industry, which requires so much capital.”

Matthew Burt, senior vice president for Renewable Energy Systems, said the gradual reduction of the PTC will be a challenge to the wind industry. Over “the next few years … we have to get the prices down,” he said. “The wind itself is free, but the equipment is very expensive.”

William Golove, whose eponymous firm provides consulting services to renewable energy project developers, agreed. “If wind wants to remain competitive, it will have to find ways to generate more out of the assets it has, or reduce the costs of doing so,” he said.

Ward Marshall, director of business development for independent power producer Pattern Development, said despite legal challenges, “We’re definitely being very bullish on the [Clean Power Plan]. We think it will have an effect on the ERCOT market. It’s kind of happening. It’s coming.”

Jeff Ferguson, senior vice president for project development for Apex Clean Energy, which builds utility-scale renewable projects, said ERCOT has helped make renewables attractive to corporations not in the energy business.

“I would like to pat ERCOT on the back, because a lot of the [commercial customers] Apex is doing business with can only do business if they’re operating in some sort of synthetic” power purchase agreement, he said. “They need an open market where they can get that synthetic PPA and swap it. You can’t do that in a lot of markets. … I see more explosive growth this side of the business once the PTC expires.”

Solar Needs Infrastructure

Paul Wattles, senior analyst for market design and development for ERCOT, said Texas needs to invest in more infrastructure to maximize solar power. “The best solar potential is West Texas, but the further west you get, the fewer lines we have. If we’re going to get to areas where you have the best solar irradiance, we’re going to need more wires outside the [Competitive Renewable Energy Zones] process.”

Kate Sherwood, senior director of central project development for SolarCity, said her company’s contracts with Wal-Mart have all been economic deals, rather than premised on their green attributes. “The large customers don’t see the risk” of bad contracts, she said. “They see the credits they receive helping them offset the risks.”

“We’ve matured to the point with utility-scale solar where we’re competing with traditional forms of generation,” said Randall Jenks, director of commercial operations for OCI Solar Power, which owns and operates projects in the U.S. and Mexico. “Now, when I go out and talk about PPAs, I’m talking about the future variables of gas. … If you wanted to build a simple combined cycle 15 years ago, it was easy to get a 20-year gas contract. Try to do that now. The average gas contracts are one, two years.”

Like wind, solar power will need to reduce costs with the phase-out of the investment tax credit, said Colin Meehan, director of regulatory and public affairs for First Solar. “Having some predictability is going to be important. The good thing with the phase-out is we’re going to find cost improvements.”

Charlie Hemmeline, executive director of the Texas Solar Power Association, also was confident. “As the [subsidy] fades out, the solar industry will find a way to sell, one way or the other,” he said.

A Place for Storage?

“We do have a lot of policy lifting to do with [energy] storage,” said Mark Bruce, a principal with Cratylus Advisors. “There’s nothing about storage in the [ERCOT] protocols, for instance. The system sees generation and loads. It’s going to be a while before we reach the point where we have strong storage policy from a system perspective.”

Bruce and Ryan O’Keefe, senior vice president of business development for equipment provider Ideal Power, said increasing demand charges will increase the number of customers who abandon the grid.

“A business can say, ‘I’ve got meters, I’ve got connected meters ready for storage … I can defect from the grid or at least have a choice of doing so,’” said O’Keefe. “We’re starting to see the economics make sense for businesses managing their energy profile.”

Jeff Wehner, vice president of renewables operations for Duke Energy Renewables, sees value in upgraded lithium batteries. “We see the value in ancillary services more than anything else,” he said. “I can’t speak for ERCOT, but I think they see the value we provide.”

“One of the things that’s holding back storage and other resources is how much of a comfort level does ERCOT have with these resources being there,” said Chad Blevins, senior consultant with The Butler Firm, which provides legal and consulting services on clean and renewable energy transactions.

Khalil Shalabi, vice president of energy market operations and resource planning for Austin Energy, said the impact of large renewables can be seen in pricing. “What I can’t wait for is all the solar penetration on the grid,” he said.

Demand Response

David Oberholzer, vice president of business and partner development for Weatherbug Home, said ERCOT is attractive to companies like his that are trying to increase the penetration of grid-connected thermostats, now about 12% nationally. “There’s a lot of customer churn in the [retail] space that makes it difficult to monetize thermostats or take on the risks. … In Texas, you have a whole market you can go to at once.”

Evan Pittman, associate director of corporate strategy for Comverge, said third-party demand response providers’ lack of access to ERCOT’s energy market is a challenge for expanding DR.

But he said non opt-in entities — electric cooperatives and municipally owned utilities that do not operate as competitive retailers and don’t allow customers to choose alternate suppliers — provide an opportunity for DR. “They don’t have to worry about customers leaving in two years and they can operate their own distribution systems, so they can decide where this goes. [They] have a golden opportunity to act now.”

Nathan Mancha, director of demand response for EDF Energy Services, said ERCOT’s penetration rate of connected thermostats creates a market for residential DR. “We know some older generation in ERCOT will have to go away. If we take the time to replace them, we need to think how the residential side can be used to bridge the gap,” he said. “We have an open market [in Texas] that is willing to try new things.”

March 8, 2016

MISO Delays Seasonal, Locational Capacity Constructs

By Amanda Durish Cook

MISO will delay the introduction of seasonal and locational capacity constructs for a year, officials revealed Wednesday during the RTO’s first-ever Resource Adequacy Subcommittee meeting.

MISO acknowledged that it missed its original goal of making a FERC filing in December and now hopes for a May filing, said Executive Director of Resource Adequacy and Transmission Access Planning Renuka Chatterjee, who conducted the meeting as stakeholders were still working through selections for chairman and vice chairman.

“Let us have some additional time to look through anything we’re missing” before making the filing, Chatterjee told stakeholders.

The delay means the changes won’t be implemented until the 2018/19 planning year.

Two Seasons

MISO is contemplating two procurement seasons: a four-month summer season spanning June to September and an eight-month winter covering October to May. The locational change would allow for the formation of external resource zones for resources outside MISO and create capacity transfer rights for load-serving entities with long-term supply arrangements. (See MISO Proposes Two-Season Capacity Market.)

Chatterjee said the delay will ensure time for obtaining FERC approval and allows MISO time to define new reserve value requirements, capacity accreditation and capacity import limits. “We want to make sure [stakeholders’] commercial structures will be ready,” she explained.

Laura Rauch, MISO’s manager of resource adequacy coordination, said the delay was in response to stakeholder requests. “However, the same general proposal will hold. There will still be a two-season construct … and capacity accreditation will be based on planned outages,” she said.

Mark Volpe, senior director of regulatory affairs for Dynegy, said MISO should consider pushing the filing back to early July to give the RASC time to hold more meetings. “At Dynegy, we applaud the plan to defer this for a year,” Volpe said.

In light of the delay, the RASC decided to postpone a vote on new Tariff language implementing the seasonal construct. “We still think a vote is important, but for now we’d like to pull it back,” said Matt King of electricity consulting firm GDS Associates.

Changes to Capacity Transfer Rights

MISO’s Joe Milli said the RTO wants to make two changes to the draft Tariff language regarding capacity transfer rights. He said the consideration of transmission upgrades that increase capacity import limits and resources impacted by upcoming zonal boundary changes would come before historical supply arrangements and cost-shared projects in the capacity transfer rights hierarchy.

The changes stemmed from stakeholders asking if they would have a tool to protect themselves from risks resulting from the creation of external resource zones. Milli said auction clearing prices for external resources are currently priced at “whichever local resource zone they sneak into.”

MISO also announced that it will not apply different capacity accreditations when dealing with planned outages in resources that clear versus resources that do not clear. The RTO said its “proposed process will include planned outages during critical periods in capacity accreditation,” and that situation could become complicated for units that do not offer as capacity resources during a season, if they were treated differently than clearing units.

“We want to make sure the same paradigm applies to baseline units that clear over units that are new or units that were freshly clearing. Our concern is when those resources re-enter the auction, are we treating them the same as resources that have cleared? It’s really making sure we have comparable treatment among resources,” Rauch said.

David Sapper of Customized Energy Solutions suggested that MISO include a rate term definition of what the RTO should pay or what units should pay in outage rates. “We used to do it in the early days of MISO, and that’s a long tortured history, but maybe we could get back to that,” he said.

Cost-Benefit Analysis Sought

Marlene Parsley of Big Rivers Electric asked if MISO could provide a cost-benefit analysis of capacity accreditation. “I don’t recall [MISO] providing a cost-benefit analysis for any of this. If we do have these numbers, can we factor those in … to see what kind of benefit we’re going to get from this?”

Rauch said MISO wasn’t comfortable providing a cost-benefit analysis since the success of capacity accreditation depended heavily on market participants’ actions.

Chatterjee said stakeholders would benefit from a future workshop on capacity accreditation. She suggested that the future chair and vice chair call a special meeting, once they’re elected.

In the meantime, Milli, MISO liaison for the Competitive Retail Solutions Task Team, said his group hopes to post a design document that includes an overall auction modification recommendation on March 18. “This group will then pick that up and debate the merits,” Milli told the RASC.

The task team is currently hearing stakeholder proposals on changes to the auction rules. Dynegy and Exelon so far have asked MISO to consider singling out Zone 4 with three-year forward auctions separate from the rest of the RTO. (See Dynegy, Exelon Propose PJM-Type Capacity Auction for MISO Zone 4.)

Chatterjee said it was too soon to tell if an auction solution will be recommended by a RASC vote. “Ultimately the goal is to make a recommendation after we’ve heard a variety of proposals and MISO’s own thinking as to what would be responsive to the issues in front of us,” Chatterjee said.

If a RASC vote does occur, it won’t be in time to effect change on April’s 2016/17 Planning Resource Auction.

To protect competitive information in local resource zones with a small number of market participants, zones 3 (Iowa), 5 (Missouri) and 7 (Michigan) will again be grouped together, said John Harmon, MISO manager of resource adequacy. Zones 8 (Arkansas), 9 (Louisiana and Texas) and 10 (Mississippi) will also be combined. The grouped zones will share planning reserve margins, local resource requirements, unforced capacity values and installed capacity values, but not capacity import and export limits, non-pseudo tied resources and local clearing requirements.

Auction Timeline

March 9: Deadline for submission of fixed resource adequacy plans (FRAPs) to MISO
March 15: MISO completes review of FRAPs
March 26: Market Monitor provides unit-specific threshold data
March 29: Auction window opens
April 1: MISO begins auction
April 14: Auction results posted

March 8, 2016January 23, 2024

Citizens Groups Seek Public Funding for FERC Interventions

By Rich Heidorn Jr.

A group of citizens groups has dusted off a forgotten provision of the 1978 Public Utility Regulatory Policies Act that it said requires FERC to provide public funding for interventions before the agency.

In a filing Monday, watchdog group Public Citizen and more than two dozen environmental and public interest groups called on FERC to create an Office of Public Participation, as they say was required by the act (RM16-9).

The act appropriated $2.4 million for compensating intervenors in fiscal year 1981, before FERC switched to its current funding mechanism, based on fees on industry participants.

“I don’t know how much money we’re talking about here,” said Tyson Slocum, director of Public Citizen’s energy program, adding that $2.4 million would be worth about $6.5 million now, adjusted for inflation. That, he said, does not include funding for the office’s staff.

Slocum said it’s unclear why the office was never created, speculating that FERC was unenthusiastic about complying and distracted by implementing other aspects of the act.

Although the Federal Power Act has been revised several times since 1978, he said, Congress never changed the public participation provision. “It just kind of dropped off the radar screen,” he said.

He said Public Citizen decided to file the petition to force compliance after informal entreaties to FERC commissioners failed to result in any action. “We’ve known about it for a long time,” he said.

The filing requests the commission to initiate a rulemaking to implement the directive.

“An Office of Public Participation is needed now, more than ever,” the petition states, noting the changes in the industry since 1978. “More ratemaking is decided in FERC-jurisdictional markets than in state utility regulatory commissions. But while state utility commissions often feature robust procedures and public money dedicated for household consumer representation, no equivalent exists at FERC, leaving entities representing the interests of households at a severe financial disadvantage compared to interests representing the owners of power plants, power marketers and transmission owners.”

FERC declined to comment.

Providing funding for ratepayer representation has also been an issue in some RTOs.

Last year, MISO rejected a request by the Public Consumer Advocates sector for $200,000 to help cover its legal costs in a fight over transmission owners’ return on equity. (See MISO to Consumer Sector: No Money for You.)

Last week, FERC approved PJM’s funding of the Consumer Advocates of PJM States. (See related story, FERC Approves PJM Funding of Consumer Advocates.)

March 8, 2016

Large Hydropower Joins the Renewable Energy Club

By William Opalka

NEWTON, Mass. — Large hydropower projects shunned by New England’s renewable portfolio standards are elbowing their way into the clean energy conversation, speakers at the 13th Northeast Energy and Commerce Association Conference on Renewable Energy said Thursday.

Hydropower projects larger than 30 MW have not qualified for financial incentives under most New England states’ standards.

But with coal and nuclear fleets shrinking, large-scale Canadian hydropower is needed to avoid an overreliance on natural gas and meet aggressive carbon reduction goals, several speakers said. Wind and solar can’t develop at scale fast enough to replace thousands of megawatts of legacy generation, they said.

“If we’re going to achieve our climate and clean energy goals under the [Massachusetts] Global Warming Solutions Act and the various states’ renewable energy targets, we’re going to need a course correction,” said Leslie Malone, a senior analyst at the energy and environmental organization The Acadia Center.

The Massachusetts law and similar legislation in Connecticut mandate a 25% cut in greenhouse gas emissions from 1990 levels by 2020 and an 80% reduction by 2050.

One potential solution, Malone said, is a “bundling” of firm hydro resources with intermittent wind energy to create a steady supply of clean power into the region.

Natural gas accounts for about half of the region’s power mix, with that percentage expected to grow. ISO-NE estimates 4,200 MW of older generation will retire in the next few years, including the 1,517-MW coal-fired Brayton Point station and the 680-MW Pilgrim nuclear plant, both in Massachusetts.

Most of the new plants that have cleared in ISO-NE’s recent Forward Capacity Auctions are natural gas generators.

David Wilby, senior vice president for state policy at SunEdison, noted that the pace of plant retirements has been faster than added capacity in recent years. SunEdison began as a solar energy developer, but in 2014 it acquired Boston-based First Wind, a developer of wind projects from Maine to Hawaii.

“As much as my company and others have added renewable megawatts as quickly as we can, we’re basically treading water … so we need big, large long-term investments to grow and to help the [power source] diversity,” he said.

The proposed Northern Pass transmission project in New Hampshire would bring 1,090 MW of Canadian hydropower into the market. (See Vermont OKs Canadian Hydro Line.)

But those projects aren’t enough to replace the retiring generation, said David O’Connor of ML Strategies, a government relations and consulting firm.

Massachusetts Gov. Charlie Baker’s proposed legislation to authorize utilities to purchase 2,400 MW of large-scale imports also is insufficient, he said. “That would be … about one-third of Massachusetts’ needs, or only 10% for the entire region,” he said. (See Baker: Hydropower Contracts Best Way to Lower Costs.)

The region’s clean energy needs are sufficiently large that Canadian projects are no longer seen as crowding out local resources, Wilby said. “It’s not hydro, or wind, or renewables; it’s ‘and’ to get us where we need to go,” he said. “It’s not one thing that’s going to get us there.”

March 8, 2016

2015 RTEP Reflects $3.2B in Spending, Shift to Natural Gas

By Suzanne Herel

Low load growth and the shift from coal- to natural gas-fired generation mean a need for smaller and fewer baseline transmission projects, PJM said in its 2015 Regional Transmission Expansion Plan report last week.

A slow recovery from the last recession and evolving customer behavior — such as more efficient home appliances and behind-the-meter solar installations — have stunted load growth, the report said.

Those drivers also have lessened the need for new large-scale transmission projects.

In 2015, the Board of Managers approved 214 new baseline projects totaling $1.9 billion and 207 new network transmission projects totaling $1.3 billion.

The $3.2 billion total represented a $2.6 billion net increase in approved projects since the end of 2014. The new projects were partially offset by cost changes in existing projects as well as the removal of 202 network projects representing $677 million and 42 baseline projects totaling $300 million.

Among the new projects was the controversial stability fix at Artificial Island in New Jersey, home to the Hope Creek and Salem nuclear reactors. (See FERC Questions Fairness of Artificial Island Cost Allocation.)

The canceled network upgrades were the result of the withdrawal of 157 generation interconnection requests, a quarter of which were for wind-powered units. Together, the requests totaled 15,302 MW. Withdrawals can reflect developers’ reactions to capacity auction prices and public policies on renewable fuel, PJM said.

The report notes the continuing shift from coal to natural gas because of plant retirements driven by environmental regulations and competition from cheap natural gas from the Marcellus and Utica reserves. PJM also is seeing new wind and solar units being encouraged by federal and state renewable energy incentives, while load has been tempered by demand resources and energy efficiency programs.

“Market activity suggests that total natural gas-fired generation capacity may exceed coal within several years,” the report said.

PJM projects 20,300 MW of coal will have retired between 2011 and the end of 2016, much of which is more than four decades old.

In 2015, PJM received deactivation notices totaling 1,626 MW, down from 4,291 MW the previous year and 7,745 MW in 2013. That compares with a total of 11,000 MW for the eight years ending Nov. 1, 2011.

Of all the active, under construction and suspended generation interconnection requests received by the end of 2015, more than 72% were for natural gas, more than 17% involved wind power and 2% represented nuclear units.

To address thermal and voltage reliability issues, PJM now includes low load and winter peak system conditions in its regional planning criteria.

Since 1999, PJM’s board has greenlit nearly $28.3 billion in transmission system upgrades, including $23.5 billion in baseline projects and $4.8 billion in facilities needed to connect more than 71,000 MW of new generation.

March 8, 2016

FERC Approves PJM Funding of Consumer Advocates

By Suzanne Herel

FERC last week approved PJM’s creation of a funding mechanism to support the Consumer Advocates of the PJM States (CAPS) through a charge to electric customers.

Consumer advocates of pjm states (caps) — Dan Griffiths, Executive Director of CAPS *© RTO Insider*

Commissioner Tony Clark dissented from the vote, saying never before had FERC “endorsed the policy that the activities of non-decisional intervenor groups be funded through a dedicated utility tariff under the auspices of the [Federal Power Act]” and that it set a “troubling precedent” (ER16-561).

CAPS’ participation in the stakeholder process should be funded through the appropriations of state legislatures, Clark said.

Beginning next year, CAPS will receive an initial annual budget of $450,000. FERC approval would be needed for any budget increase of more than 7.5%.

“This authorized 7.5% annual increase is described in the filing as a way to ‘promote fiscal restraint,’” Clark wrote. “Only in government could a budget that allows for a near doubling every decade be considered parsimonious.”

The assessment for a residential consumer using 12,000 kWh per year would be eight-tenths of a cent. The charge will be itemized on customers’ bills.

The proposal was approved by PJM stakeholders in October by slightly more than 81% of a sector-weighted vote. (See PJM Members Agree to Fund Consumer Advocates Group.)

The group also would receive a one-time infusion of $350,000 from Exelon if the D.C. Public Service Commission approves the company’s acquisition of Pepco Holdings Inc. (See Exelon Not Quitting as Observers See Little Likelihood of Salvaging Pepco Merger.)

Those supporting the filing included the Independent Market Monitor, various state agencies, Exelon and the PJM Industrial Customer Coalition.

“The Market Monitor offers that [the] CAPS funding schedule is a ‘meaningful first step to obtain needed balance in the PJM stakeholder process’ and that ‘PJM consumers have been systematically underrepresented,’” the order said.

Opposing the funding were the PJM Power Providers Group, Talen Energy and Essential Power.

Protesters argued that FERC did not have the jurisdiction to approve the funding scheme, that PJM transmission customers that serve load would be forced to fund private speech with which they might disagree, and that CAPS’ comments cannot be considered government speech, in part because not all of its members are government representatives.

CAPS, made up of consumer advocates from PJM states and D.C., was formed in 2012 with start-up funding from a FERC enforcement settlement with Constellation Energy (IN12-7-00).

The budget approved by FERC may be used for staffing and travel costs for the consumer advocates to participate in meetings. The funding may not be used for activities related to the proceedings of state or federal agencies other than FERC, litigation of matters at FERC stemming from Tariff or operating agreement changes by PJM or the hiring of counsel or expert witnesses to support the filings of other parties.

March 8, 2016

FERC Accepts Ginna Settlement

By William Opalka

FERC on Tuesday approved New York regulators’ plan to keep the Ginna nuclear power plant operating but objected to elements that it said encroached on its jurisdiction over wholesale power markets (ER15-1047).

R.E. Ginna nuclear plant, near Rochester, N.Y. (Source: Exelon) — R.E. Ginna nuclear plant *Source: Exelon*

The commission ruled that the reliability support services agreement between the R.E. Ginna nuclear plant and Rochester Gas & Electric approved Feb. 23 by the New York Public Service Commission was just and reasonable. (See NYPSC OKs Ginna Deal.)

The RSSA is between distribution utility RG&E and Exelon’s Constellation Energy Group, which had threatened to close Ginna because it was losing money. RG&E will charge ratepayers $425 million to $510 million to cover Ginna’s full cost of service, with the final amount determined by Ginna’s revenues from the NYISO wholesale market. The utility also will apply $110 million in customer credits to the contract, making the total price tag as high as $620 million.

A parallel proceeding at FERC reviewed elements of the settlement, but it was suspended in January when it was apparent that most contested items were resolved in the state docket. However, one remaining issue was whether there was a sufficient disincentive for Ginna to prevent it from re-entering the market after the RSSA ended on March 31, 2017.

The environmental group Alliance for a Green Economy (AGREE) had contested that part of the settlement as inadequate.

AGREE says the $20.1 million capital recovery balance Ginna would have to repay if it re-enters the NYISO markets should be netted against RG&E’s one-time settlement payment of almost $11.5 million to Ginna, meaning the plant’s penalty would be only $8.6 million over two years, or 2% of the plant’s revenue.

FERC disagreed.

“The settlement payment represents costs that Ginna will have incurred during the settlement RSSA’s term, but, due to timing, Ginna will not yet have recovered those costs from RG&E by the end of the settlement RSSA’s term,” FERC said. “Therefore, we are not persuaded that Ginna’s recovery of those costs … should be netted against the capital recovery balance in assessing whether the capital recovery balance provides an adequate disincentive for Ginna to return to the NYISO markets.”

The commission ordered changes to elements of the settlement agreement and RSSA that it said could infringe on FERC’s jurisdiction because they allow the New York PSC to approve all aspects of the RSSA, “including the wholesale aspects of the settlement RSSA, and potentially reduce a wholesale rate in the settlement RSSA.”

Under Supreme Court precedent, the commission said, “once [FERC] approves a wholesale rate, a state commission must allow 100% of the wholesale rate to be passed through to customers in the utility’s retail rate design.”

FERC also ordered removal of language related to a reliability-must-run agreement that state officials may approve after the RSSA expires. NYISO is in a separate proceeding before the commission to address RMR concerns in New York. (See FERC Orders NYISO to Standardize RMR Terms in Tariff.)