Below is a summary of the issues scheduled to be brought to a vote at the Markets and Reliability Committee on Thursday. The Members Committee held its monthly meeting last week at PJM’s Annual Meeting. (See related coverage, PJM Annual Meeting Celebrates RTO’s First 90 Years.)
Each item is listed by agenda number, description and projected time of discussion, followed by a summary of the issue and links to prior coverage. RTO Insider will be in Wilmington, Del., covering the discussions and votes. See next Tuesday’s newsletter for a full report.
Markets and Reliability Committee
2. PJM Manuals (9:10-9:40)
Members will be asked to endorse the following manual changes:
C. Manual 14D: Generator Operational Requirements. Revisions to develop requirements for solar generation facilities, in compliance with FERC Orders 828 (Requirements for Frequency and Voltage Ride Through Capability of Small Generating Facilities), issued July 21, 2016, and Order 764 (Integration of Variable Energy Resources) issued June 22, 2012. (See FERC Issues Ride-Through Requirement for Small Generators.)
D. Manual 36: System Restoration. Revisions developed in response to a periodic review.
E. Manual 13: Emergency Operations. Attachment E updated with 2017/18 load forecast and Mid-Atlantic load shed allocation information; Attachment F updated with 2017/2018 load shed capabilities and allocation percentages. The data in the attachments affects only transmission owners and has been validated by them.
3. New Black Start Unit Annual Revenue Requirements (9:40-9:55)
Members will be asked to endorse manual and Tariff revisions regarding the annual revenue requirements for new black start units. (See “PJM to Review Black Start Prior to New RFP,” PJM Market Implementation Committee Briefs.)
4. Monthly Meter Correction (9:55-10:10)
Members will be asked to endorse manual revisions to allow for monthly correction of meters for pseudo-tied units and dynamic schedules. (See “Meter Correction Initiative OK’d,” PJM Market Implementation Committee Briefs.)
Members will be asked to endorse a proposed problem statement and issue charge to consider ways to incorporate upgrades approved in the Regional Transmission Expansion Plan in the network model used for FTR auctions. PJM is proposing the initiative out of concern that clearing prices for long-term FTR auctions may not fully reflect future system capabilities.
7. Incremental Auction Senior Task Force (IASTF) Update (10:50-11:00)
Members will be asked to approve an updated charter for the IASTF, which was created in response to a problem statement by Direct Energy that was approved by the MRC in November 2016. The revisions reflect an increase in scope resulting from a problem statement by NRG Energy on replacement capacity that was approved in March 2017. The revisions set a target for completing work and making recommendations to the MRC by January 2018. (See “Stakeholders Approve Variety of Actions,” PJM Markets and Reliability and Members Committees Briefs.)
PJM’s first capacity auction requiring year-round availability saw prices drop by one-quarter in most of the RTO, with only the EMAAC and Duke Ohio-Kentucky regions recording increases.
Base Residual Auction prices fell to $76.53/MW-day in most of the RTO, down from $100 last year. ComEd dropped to $188.12 from $202.77, and MAAC, which cleared with the RTO at $100 last year, dropped to $86.04. EMAAC, which cleared at less than $120 last year, jumped to $187.87, while the Duke region, which did not price separately from the RTO last year, cleared this year at $130.
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This was the first year in which all generation must be Capacity Performance, meaning it’s expected to be available throughout the delivery year and faces stiff penalties for nonperformance.
It was also the first year under relaxed seasonal aggregation rules, which resulted in almost 400 MW of capacity pairing winter generation (mostly wind) with summer solar, demand response and energy efficiency.
With seasonal DR no longer allowed — outside of that matched with other resources through aggregation — price-responsive demand (PRD) participated for the first time in this year’s auction. PJM members committed to 558 MW of demand reductions under PRD.
The auction also followed Illinois’ approval in December of zero-emission credit subsidies for nuclear plants. Exelon said neither its Quad Cities plant in Illinois nor its Three Mile Island nuclear plant in Pennsylvania cleared the auction.
Load Forecast Down
The auction reflected a 2.1% reduction in forecast peak load from last year’s level to 153,915 MW. The reliability requirement was reduced by 2,800 MW from DY 2019/20 because of the lower peak forecast and the PRD elections.
“When the reliability requirement goes down for the same amount of [available] capacity, it’s going to yield a lower clearing price,” said Adam Keech, PJM’s executive director of market operations, in a press conference Tuesday.
PJM acquired 165,109 MW for 2020/21, down about 2,000 MW from last year and providing a 23.3% reserve margin — the highest ever in the 14-year history of the BRA, and well above the required 16.6%.
About 189,918 MW was offered into the BRA, out of about 213,000 MW that was eligible, a decrease of 4,325 MW from last year’s offers.
Keech said the auction will cost load a total of about $7 billion in 2020/21, about the same as for 2019/20.
In total, about 3,144 MW (UCAP) of new generation offered into the auction including uprates, down 3,400 MW from last year. About 2,824 MW of the new generation cleared, mostly natural gas combined cycle and combustion turbines. (See related story, Analysts See End to New Builds in PJM Capacity Results.)
Almost 4,000 MW of capacity imports cleared, up 121 MW (3%) from last year, most of them from west of PJM. Combined with internal generation of almost 152,000 MW, generation made up 94% of the capacity acquired, with DR (7,820 MW) and EE (1,710 MW) making up the balance.
Price Separation
Prices in ComEd, MAAC and EMAAC separated from the rest of the RTO in response to unit retirements and increased transmission congestion in those regions, requiring the acquisition of local generation, said Keech. The Duke region clearing price increased because “we would need to incentivize locational capacity specifically in that area due to retirement,” Keech said.
“We have units that are at financial risk in the area that, if they retire, it could create a reliability issue,” he said.
Although Keech said confidentiality requirements restricted him from going into detail about which units were involved, the creation of the Duke Ohio-Kentucky and Dayton, Ohio, locational deliverability areas were apparently driven by the scheduled 2018 retirements of Dayton Power and Light’s Killen and Stuart coal-fired plants. At 2,700 MW, the plants represent more than half of the capacity in the Dayton LDA.
The Dayton LDA, however, cleared along with the rest of the RTO.
Seasonal Aggregation
Under relaxed rules that allowed aggregation across LDAs, 398 MW of seasonal capacity cleared. PJM filed plans with FERC in October, without stakeholder consensus, to ease restrictions on how seasonal resources can aggregate and offer into the BRA. With FERC lacking a quorum, staff tentatively approved it in March, and PJM quickly established rules in time for the auction. (See PJM Outlines Aggregation Rules for Upcoming Capacity Auction.)
The figure includes intermittent resources that exhibit seasonal performance differences, such as wind, which performs better in winter, and solar, which performs better in summer. It also includes DR resources, many of which are unavailable in the winter.
DR accounted for about 289 MW of the summer seasonal product, while EE accounted for about 103 MW and solar generation the remaining 6 MW. All 398 MW of wind seasonal product was supplied by generation, and Keech said wind accounted for 384 MW of it.
Keech said there were “quite a number” of winter capacity injection rights that didn’t get used as part of the seasonal aggregations.
“Certainly, from our perspective, we would have loved to see some more participation in that area,” he said. “Given that we have 400 MW that we otherwise wouldn’t have ever had, I think that’s successful.”
Renewables as CP
Another 504 MW of wind cleared as CP, for a total of 888 MW of wind (6,828.5 MW nameplate capacity at a 13% capacity factor). That was down about 80 MW from last year’s auction.
An additional 119 MW of solar cleared as CP beyond the seasonal aggregation. The 125-MW total (about 330 MW nameplate at a 38% capacity factor) was down 210 MW from last year’s auction.
Demand Response, EE
The amount of intermittent resources offered as CP dropped by 3,400 MW from last year, while DR offers fell by 2,085 MW compared with total DR offers for 2019/20.
DY 2020/21 will see a 2,816-MW net decrease of DR from 2019/20 to 7,532 MW and a 195-MW increase of EE to 1,710 MW.
The filing to ease the seasonal aggregation rules came after only 6% of DR cleared last year as CP. Stu Bresler, PJM senior vice president of operations and markets, said 4,700 MW of DR could have qualified as CP but didn’t clear economically. This year, 76% of EE and 79% of DR cleared.
Subsidy Impacts
Keech said he couldn’t discuss the specific impacts of the Illinois ZECs on clearing prices.
Aside from Quad Cities and TMI, Exelon’s nuclear plants in PJM did clear, with the exception of Oyster Creek, which did not participate because it is scheduled to retire in 2019.
The company “remains fully committed” to keeping Quad Cities in operation, “provided that [Illinois’] zero-emissions credit program is implemented as expected and provided that Quad Cities is selected to participate,” Joe Dominguez, Exelon’s executive vice president of government and regulatory affairs and public policy, said in a statement. The ZEC program, to be implemented by the Illinois Power Agency, has not yet been implemented.
The company used the results to call for an expansion of ZECs to Pennsylvania, noting that it was the third year in a row that TMI left the capacity auction empty-handed. “Exelon has been working with stakeholders on options for the continued operation of TMI, which has not been profitable in five years.”
Another generator looking for nuclear subsidies is FirstEnergy, which has been pressing Ohio officials for aid for its 889-MW Davis-Besse nuclear plant near Toledo and the 1,231-MW Perry plant near Cleveland. (See FirstEnergy Hopeful on State, Federal Support.)
The company’s hopes suffered a blow last week when the chair of the Ohio House Public Utilities Committee suspended hearings on the subsidy without calling for a vote. “I am not sensing a keen desire on the part of the House members to vote on this and doubt that we will have more hearings in the near future unless something cataclysmic should happen,” The Plain Dealerquoted Chairman William Seitz.
But the auction brought some good news for the company. Asked whether Perry and Besse-Davis cleared the auction, spokesman Doug Colafella responded: “Yes, a portion of all of the units FirstEnergy Solutions bid into the auction cleared.”
Also reporting on its fortunes was Dynegy, which said Wednesday that it cleared 10,217 MW, representing $456 million in revenue at a weighted average of $122.19/MW-day. That included 9,772 MW from the company’s PJM fleet ($124.27/MW-day) and 444 MW exported from MISO ($76.53/MW-day).
Still Getting Gas
Gas-fired units continue to benefit from ongoing pipeline constraints that have built up a glut of natural gas and depressed prices in the Marcellus and Utica shale regions throughout PJM’s footprint. Despite clearing prices of approximately 26 to 66% of the net cost of new entry, the auction attracted 2,350 MW of new gas-fired generation.
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“I think it’s intuitive that that [gas entry] will slow down given that the prices are below” net CONE, Keech said.
Price Responsive Demand
PJM members committed to 558 MW of demand reductions under PRD, with the BGE (330 MW), PEPCO (170 MW) and EMAAC (58 MW) LDAs participating.
Unlike DR, which is counted on the supply side, PRD is deducted from the reliability requirement, shifting the LDAs’ demand curves to the left.
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NRDC Critical
Jennifer Chen of the Natural Resources Defense Council was disappointed that wind, solar and DR resources declined compared to last year and that the RTO “is continuing to rely primarily on fossil fuels and nuclear.” She blamed the “arbitrary” CP rules for creating a “preference” of gas and nuclear over “clean power” and argued that the new seasonal aggregation rules squeeze out many summer-only resources that can’t find winter-only resources to pair with for the auction.
She also criticized PJM for securing too much capacity, saying consumers are paying more than they should pay for reliability.
Predictions
Results largely defied expectations, fueling a recurring complaint among market participants about the market’s volatility.
Earlier this month, ICF analysts Rachel Green, Himanshu Pande and George Katsigiannakis predicted prices would exceed $100/MW-day as the 100% CP requirement offset downward pressure from increased supply and lower demand. They predicted the EMAAC, ComEd and Dayton LDAs would see price separation from the rest of the RTO.
Julien Dumoulin-Smith, an analyst with UBS, predicted in March that the ComEd region would break $200/MW-day, and in April that EMAAC would remain “roughly flat.” He did, however, note changes to transmission accounting that would cause EMAAC to clear separately from the rest of the RTO and cautioned that demand reductions would likely depress clearing prices.
No analysts could be reached Tuesday for comment on the results.
CAISO stakeholders last week voiced skepticism about the effectiveness of a new ISO initiative to prevent early retirement of unprofitable generators that will be needed to ensure grid reliability as California progresses on its aggressive renewable energy goals.
The ISO wants to limit the scope of its “risk-of-retirement” initiative to improving processes for its existing Capacity Procurement Mechanism (CPM), which includes a set of “backstop” provisions that enable the ISO to bypass its wholesale market to directly compensate generators under exceptional circumstances.
“We’ve had the CPM risk-of-retirement Tariff provisions in place for a number of years, and we’ve heard from suppliers that they think that those provisions are — for lack of a better word — clunky,” Keith Johnson, CAISO manager of infrastructure policy and contracts, said during a May 18 CPM Risk-of-Retirement Process Enhancements working group meeting to kick off the initiative.
Unaddressed Issue?
But some market participants say the initiative will fail to address a looming and critical issue: that CAISO’s energy market can no longer adequately compensate the construction and operation of the kind of resources needed to support the grid as California moves to meet its 50% renewable portfolio standard by 2030.
The effort specifically aims to address the circumstances of gas-fired plants that are not currently needed for resource adequacy (RA) and do not earn enough money in the wholesale market to remain financially viable but will likely be needed in the future as other units shut down because of state environmental standards prohibiting once-through cooling.
CAISO wants to build a clear “bridge” that would provide a needed supply resource with a limited period of out-of-market payments until the plant is able to obtain an RA contract from a load-serving entity.
Under existing rules, only resources not currently under an RA contract are eligible for a CPM risk-of-retirement designation. A resource still under contract must wait until its agreement expires before making an application.
The application must include an offer price as well as an attestation signed by an executive officer stating that the resource is uneconomic and that retirement is inevitable without the CPM designation. Once that information has been submitted, the ISO undertakes a study to determine whether the unit will likely be needed for RA during the compliance period two years out.
Timing Problem
A key problem for resource owners: CAISO cannot initiate its study to determine the need for an individual unit until November of each year, just after all LSEs publish their RA requirements for the following calendar year. That gives a resource just two months’ notice before losing an RA contract, followed by a three- to four-month ISO study and stakeholder comment process, leaving the resource owner in financial limbo for an extended period. Through process changes, the ISO hopes to provide a resource a financial bridge to get from the next year — for which it lost its RA designation — to the following year, when it is assumed to be needed.
Mark Smith, a vice president at Calpine, said that even if the ISO could issue a CPM designation as early as November, it wouldn’t provide his company enough time to weigh the decision of whether to keep operating a potentially money-losing plant.
“We’re making business decisions on maintenance. We’re making business decisions on employment of people. We’re making business decisions that cannot be done in a few weeks or a couple of months’ timeframe,” Smith said. “These are multimillion-dollar assets — sometimes hundreds of millions of dollars.”
Earlier this year, CAISO awarded reliability-must-run designations to two Calpine peaking plants after the company said it would be forced to retire the facilities if required to await a CPM decision next year. (See CAISO RMRs Win Board OK, Stakeholders Critical.)
Calpine sought to extend the operation of its Yuba City peaking plant through a reliability must-run award rather than the risk-of-retirement provision of CAISO’s Capacity Procurement Mechanism. | Calpine
“What we found ourselves in was a situation that the only viable option was to use an RMR contract,” Johnson said. “So what we’re trying to do in this initiative here with CPM is to address at least some of these process enhancements so CPM can be used as, more or less, the first and primary backstop procurement option.”
CAISO won’t produce a proposal on the issue until it receives stakeholder comments after a second working group meeting May 25. Johnson emphasized that the ISO wants the initiative to zero in on the process for applying for a CPM designation — including the timing and deadlines for studies, rather than dealing with the costs or terms of CPM contracts.
Johnson also assured stakeholders that CAISO would not use CPM to circumvent other procedures in place, such as the RA program administered by the California Public Utilities Commission, which relies on ISO studies to determine statewide needs for system, local and flexible capacity carried by the state’s utilities. The ISO’s own RA efforts focus on complementing that program by developing market mechanisms to procure increasing amounts of flexible capacity.
Michele Kito, a PUC regulatory analyst, expressed concern that the ISO would start to use an updated CPM process under more than just “extraordinary circumstances.”
“We don’t envision using this more frequently than we do now, in the sense that it’s really just making the process work better,” Johnson responded. “I mean it’s possible that you might see more CPM risk-of-retirement if more units become at risk of retirement, because — remember — this is really a backstop mechanism.”
While Tyrone Hillman, a principal with Pacific Gas and Electric, said he understood the ISO’s need to narrow the scope of the initiative, he pointed out its overlap with another effort that could allow certain unprofitable generators to temporarily suspend operations short of full retirement. (See CAISO Initiative Could Toss Lifeline to Struggling Generators.)
Johnson acknowledged the “potential” overlap between the two efforts, but said the ISO wanted to keep them separate to ensure the ISO Board of Governors approves at least one of them later this year.
“If one of the initiatives gets bogged down, then hopefully it wouldn’t bog down the other initiative,” Johnson said.
‘Elephant in the Room’
“The elephant in the room is killing me, so I’m going to bring it up,” said Eric Little, manager of wholesale market and greenhouse gas market design at Southern California Edison. “We have to recognize that the state has goals to go to low — if not zero — GHG emissions from the electricity sector.”
Getting there will mean increased reliance on renewable resources, translating into a larger number of market intervals with “very low” to negative prices, Little said.
Prior to the high penetration of solar on the California system, generators without RA contracts could earn sufficient revenues from the energy market, Little said. That opportunity is dwindling.
“So the question in front of us is how to we get from here — where we have been with that environment — to an environment in which we no longer have any thermal resources on the system,” Little said. He joked that California might never achieve that goal if nobody is consuming electricity at all “because the lights are out” because of low system reliability.
“I think recognizing all the different pieces that have to work is important thing,” Little said.
Calpine’s Smith pointed to the “huge shift in pricing dynamics” over the past two years, which leaves peaking units running just 5% of the time and earning just 50 cents/kW-month, too little to cover property taxes, let alone operation and maintenance costs.
“Eric is right. What we need here is a thought-out plan to transition us to the new world, and part of that plan has to involve — at least from Calpine’s perspective — the confirmation that units needed for local reliability are locked in and able to do all the stuff they need to do to manage the transition while the transition occurs,” Smith said.
“That’s way beyond CPM, way beyond the very narrow issue, Keith, that you’ve defined here, but that is the elephant that needs to be addressed.”
The Organization of MISO States has adopted a stricter protocol for entering closed session during board meetings.
OMS will now require requests for closed session be circulated a few days before a meeting with an explanation for the private conversation. If an objection is raised, the OMS Executive Committee will decide by simple majority if the topic deserves closed session treatment. Acceptable closed session topics include personnel and legal matters, discussion of commercially sensitive materials, and issues subject to attorney-client privilege. (See “Closed Session Procedure Outlined,” OMS May Add Voice to Pseudo-Tie Fracas.)
“At least in Wisconsin, we have to assume that meetings are open. … You better have a darn good reason to go closed,” Wisconsin Public Service Commissioner Michael Huebsch said at the May 18 OMS board meeting.
The new rule was approved by acclimation.
OMS President and Indiana Utility Regulatory Commissioner Angela Weber led the move to draft new rules after some organization members requested a closed session in February to discuss MISO and PJM’sFERC filing to implement targeted market efficiency projects. OMS held closed sessions again this spring over the creation of a seams policy document. Neither of the matters warranted closed discussion, Weber said.
MISO May End Automatic Steering Committee Leadership Posts
MISO stakeholders are considering a change to the Stakeholder Governance Guide that could shake up Steering Committee membership, and OMS is telling its members to prepare for a sector vote next month during the RTO’s Board of Directors week.
The vote could allow a Steering Committee leaders to be selected through an independent stakeholder vote.
Under the Stakeholder Governance Guide, the vice chair of the Advisory Committee serves as chair of the Steering Committee, with the Advisory chair serving as the Steering vice chair.
Manitoba Hydro’s Audrey Penner currently serves as the Advisory Committee chair and the Steering Committee’s vice chair; NRG Energy’s Tia Elliott is the Steering Committee chair and Advisory Committee vice chair.
Ted Thomas, chair of the Arkansas Public Service Commission, said OMS members should be prepared for an Advisory Committee vote to change the governance guide at the June 21 meeting in Branson, Mo., although no agenda items are yet listed for the meeting. A vote in favor of severing the Advisory Committee leadership from the Steering Committee leadership might trigger Steering to hold an almost-immediate election for new leadership, as the selection method of its current leadership would no longer be valid, Thomas said.
“Now, generally I think that it is a good idea, and I don’t have any conflict with it. But it might be a problem if the people in those positions have [problems with their own removal]. To me, the juice isn’t worth the squeeze [if there are problems],” Thomas said.
He said he didn’t want the move to create any “dramatic” issues with a sudden change in leadership.
“It’s a dangerous precedent to make it immediate, and just remove the people there,” Huebsch said.
MISO spokesperson Mark Brown confirmed that some stakeholders have “initiated conversations about the idea of having separately elected Steering Committee leadership” but declined to identify who. He said MISO’s Stakeholder Relations team has yet to receive any motions or agenda suggestions for the June Advisory Committee meeting.
CHICAGO — The times, they are a-changing — again. How will companies respond?
Executives from a utility, an independent power producer, a large industrial customer, a municipal power company and a power retailer met in a panel discussion at PJM’s Annual Meeting last week to answer that question. Unsurprisingly, their answers differed based on their role in the markets.
“We are in an energy transition. … Every company in this room is going to have to figure out how to participate in an energy transition, and if we don’t, we’re going to get run over,” said Larry Stalica, president of Linde Energy Services. “I believe there’s enough smart people in this room to figure out how to get from Point A to Point B.”
Linde, whose industrial and medical gas production facilities are big power users, became its own load-serving entity in March 2003. “We realized that these wholesale markets were going to be the key to controlling our costs and making our business successful,” he said. “So we wanted our voice heard.”
His call for leadership was echoed by Marc Gerken, CEO of American Municipal Power. “Don’t be afraid to break something down that isn’t working,” he said. “That’s good leadership.”
He went on to criticize PJM’s consistent tinkering with its market designs. “We get sometimes troubled with all of the changes in the market constructs. It’s tough to follow; it’s tough to keep track of; so we think that there needs to be a little more discipline on that,” he said. “We are a very transmission-dependent utility. We don’t own a lot of transmission [so] we really feel that PJM needs to focus on the reliability aspect. We think that’s your mission.”
Gerken said the competitive transmission process created by FERC’s Order 1000 allows incumbent transmission owners to pad their balance sheets with trumped up costs for supplemental projects. And “we’re just supposed to trust them,” he said.
Calpine CEO Thad Hill said his company has had to “waste” energy in the middle of the day when oversupply causes prices to go negative. “I kid you not,” he said. “I think we’re better than that.”
Direct Energy President John Schultz said weak demand could result in “incumbent market participants really fighting over a shrinking pot” of revenue.
Chris Crane, CEO of Exelon — which is battling court challenges to zero-emission credits for its nuclear plants in New York and Illinois — called on industry members to collaborate on issues, rather than litigate them.
The industry took a wrong turn two decades ago when it decided to divorce environmental and market policy, he said, resulting in renewable energy subsidies that diminish market efficiency.
“It has put us in a very difficult situation where, instead of working together to try to find ways to satisfy the environmental desires of the states, we find ourselves in court fighting over” the impact of state environmental policies on the energy markets, he said.
“Not a place that we should be. It’s a degrading situation. What we should be doing is working together on what’s the market design that [can accommodate] a state [that has] environmental programs that they desire. How do we come up with the market design that is managed at the ISO level that can incorporate that to be fair and equitable? That’s where the focus needs to go.” (See PJM Stakeholders Offer Different Takes on Markets’ Viability.)
He also questioned those who contend end-use customers want more control over their energy usage, as distributed energy resource proponents claim.
“That is where we have to decide — as we’re designing the systems of the future — how much is a trend and how much is a fad,” he said. “We have the job of protecting the customer as things go forward.
“We’re at a place … where things are changing pretty quickly,” Crane said. “As participants in the market, we need to come together. … I would much rather be having conversations with my counterparts here on what we can do constructively to fix the larger problem so we’re not having to put one-on-one Band-Aids on this marketplace.”
“I think sometimes in wholesale energy market matters and maybe even before federal regulators, it seems like things get a little distant from those who pay the bills,” said Robert Mork of the Indiana Office of Utility Consumer Counselor, and president of the Consumer Advocates of the PJM States, at the board’s annual meeting with consumer and environmental advocates May 15.
“We do ask the board to help us communicate to the PJM staff how important it is to get those who are paying, the customers, involved in the process early on as opposed to later in the process,” said Greg Poulos, CAPS’ new executive director. “We have heard PJM talk about creating more opportunities for customers to be involved in their energy choices.” (See related story, Retiring CAPS Head Dan Griffiths Feted at Annual Meeting.)
Incremental Auctions
Poulos pointed to PJM’s incremental capacity auctions as an important entry point for demand response owners, who often can’t secure resources three years into the future, as required for participation in the Base Residual Auction. He said that continual rule changes “really create a lot of chaos for customers who are willing to participate.”
Nearly two dozen representatives from the state consumer advocate programs within PJM’s footprint, along with D.C., took advantage of the sole opportunity each year to address the board. The advocates are organized through CAPS, but as Poulos explained, consensus on any issue can be hard to come by.
A prime example, he said, has been how advocates view subsidies for generation resources. It’s a “critical question,” he said, because it largely determines advocates’ preferences on how PJM should respond to state energy-policy actions.
“They’re on all sides of this issue: wanting very true markets or wanting very strong abilities for states to have state actions,” Poulos said. “We are all over the place, and that’s not a bad thing. … We need to make sure our members are educated.”
CAPS representatives also pressed the board to be mindful of costs and better integrate renewables, DR and energy efficiency. Dave Evrard, Pennsylvania’s assistant consumer advocate, noted the importance of including energy efficiency in PJM’s load forecasting model to ensure the RTO doesn’t purchase too much capacity. Poulos said PJM needs to ensure all cleared capacity is a physical resource and to protect against the “dramatic” price swings that can occur when capacity is replaced in incremental auctions.
“One of our concerns overall as a group that comes up a lot is that consumers don’t pay two times, three times or four times for these resources,” he said.
Cost Containment
Evrard also called on PJM to include cost containment measures in its competitive transmission planning process. The RTO is in the process of instituting competitive bidding rules in time for an upcoming project consideration window but has acknowledged it won’t have enough time to consider cost containment ideas.
“Consumer advocates look at cost caps and cost containment as essential consumer protection,” Evrard said. “I realize there are myriad issues. … I don’t discount those.”
He indicated he’s been paying attention to debates on the topic, including a campaign by several merchant transmission developers, including LS Power, to have cost containment be a deciding factor. (See Who Decides? Panel Highlights Blurred Jurisdiction on Tx.)
“I know there are some entities that have sort of proposed that cost containment shouldn’t just be a consideration, but rather it should be elevated so if I come in with a project that has a specific cost-containment proposal, from the very beginning, I should enjoy some sort of preference,” he said. “I don’t know if the PJM consumer advocates want to go quite that far, but … we are very interested in what emerges from that.”
PJM has yet to complete a competitively bid transmission project since FERC opened the process to competition with Order 1000. Its first attempt, a transmission line across the Delaware River that connects to the nuclear plants on New Jersey’s Artificial Island, has been mired in controversy for years. While the board resumed the project in April, complaints remain about PJM’s proposed method of allocating the costs to customers.
Representatives of Delaware, which stands to shoulder more than $260 million of the project’s projected $280 million cost, have offered the loudest and most consistent opposition, arguing that their state — which has far fewer ratepayers than other PJM member states — will be disproportionately impacted. They say PJM’s usual allocation method, which is based on resolving downstream power-flow issues, is not appropriate because the project is instead meant to resolve grid-reliability issues that are beneficial to all members.
Ruth Ann Price, Delaware’s deputy public advocate, called it “trying to fit a square peg into a round hole” and said the problem needs to be addressed communally because “if it goes badly, we’re all going to be blamed for this.”
She thanked the board for its “sensitivity” in considering Delaware’s perspective on the topic. The board suspended the project in August and called for a complete reanalysis by PJM staff. That analysis resulted in changes to the project’s scope that cut the price tag nearly in half. LS Power was awarded the project in part because its bid included cost caps that provided “greater cost certainty,” PJM said. In approving PJM’s analysis, the board instructed staff to report on cost-allocation alternatives. (See Board Restarts Artificial Island Tx Project; Seeks Cost Allocation Fix.)
For future projects, Price said, the board should require more transparency about submitted bids and ensure customers receive essential information. “States should know to a reasonable statistical approximation what these projects mean in terms of costs to their residents,” she said.
More transparency is also needed, she said, with incumbent TOs’ supplemental projects. “PJM must take more responsibility, I believe, in ensuring stakeholders that these projects are necessary and fundamental to the wellbeing of the transmission system,” she said.
Among the calls for more engagement, there was also gratitude for the inclusion that already exists. Price praised PJM for facilitating CAPS members’ involvement in transmission planning. “We welcome being a part of that process rather than be presented with a plan that is fait accompli,” she said. “We would like to have more discussion about how the project flow works, and how our states can get more involved and more knowledgeable.”
“We are so happy not to be ignorant of the implications of things that come before PJM and being in the position of just saying ‘no’ and then litigating — which 10 years ago, we were kind of in that position,” said Jackie Roberts, director of the West Virginia Consumer Advocate Division.
She praised PJM officials for having a constructive relationship with the Independent Market Monitor, Joe Bowring’s Monitoring Analytics. She said PJM CEO Andy Ott assured her during the formation of the Reliability Pricing Model capacity market that “‘a strong Market Monitor gives my markets credibility and validity.’”
Roberts said, however, that advocates are “worried” about the renewal of the Monitor’s contract when its current pact with PJM expires in 2019. In 2013, state regulators forced PJM to remove contract language that they said would undermine the independence and quality of the monitoring function. (See PJM, Monitoring Analytics Sign New Contract.)
“We’re looking forward to an easy and un-stressful contract consideration when his contract is up,” Roberts said.
‘Gross Mismatch’ in Generation Sources
Several environmental groups also outlined their concerns during the meeting with the board. Jennifer Chen of the Natural Resources Defense Council said concern over subsidies for renewable generation should be tempered by the recognition that “that almost all resources get some level of subsidies or preferential treatment.”
She said states have the right to express generation preferences through subsidies, and PJM can’t be in the position to judge which ones should trigger a repricing mechanism or the minimum offer price rule. She said a “gross mismatch” exists between what generation sources consumers want, as indicated in polls, and what is procured through PJM’s markets.
While some of the issue is in price formation, other causes could be operational. She questioned why transmission and injection rights couldn’t be seasonal to better accommodate resources that perform differently throughout the year.
“We’re in a good position to implement some changes and not be timid about it,” she said.
Mike Jacobs of the Union of Concerned Scientists took issue with PJM’s recently issued reliability whitepaper for suggesting that some technologies are unable to adapt to provide ancillary services such as frequency response, voltage control or ramping capabilities. (See PJM: Increased Gas Won’t Hurt Reliability, Too Much Solar Will.)
“We shouldn’t assume they are free and available from some providers and not from others,” he said. “The paper has essentially predetermined its outcome.”
Dan Griffiths, who retired last week as CAPS’ executive director, ended the session on a positive note, saying he is confident the PJM markets will find a way to coexist with state policies. With 13 states and D.C., Griffiths said, PJM has an advantage over single-state ISOs.
“The bigger [the RTO] is, the more it tempers state incentives to meddle in markets,” he said. “We will work out the current problem, I know.”
Vistra Energy has approached Dynegy regarding a potential takeover that would create the nation’s largest independent power producer with more than 46 GW of capacity, TheWall Street Journalreported Friday.
The Journal, citing unnamed sources, said the two Texas companies are in preliminary talks, but there is no guarantee the deal would go through.
Luminant, Dallas-based Vistra’s competitive generation arm, has 16,760 MW of capacity in Texas. Houston-based Dynegy operates about 31,400 MW of generation in the Northeast, Mid-Atlantic and Midwest (including almost 1,800 MW from plants in which it shares ownership).
Lamar Power Plant | Luminant
A Luminant-Dynegy combination would own almost 46,400 MW alone, surpassing NRG Energy, which claims to be “#1 in competitive generation” with 45,909 MW of net capacity in 29 states, including 1,120 MW of nameplate wind and solar.
The takeover would expand Vistra’s footprint beyond Texas, which saw record low wholesale prices last year. However, to do so, it would have to absorb Dynegy debt said to be about $9 billion, much of it incurred in recent years.
Dynegy entered the ERCOT market in February 2016, when it completed an acquisition of ENGIE’s U.S. power plants for $3.3 billion with private equity firm Energy Capital Partners. (See Dynegy, Energy Capital to Buy 8.7 GW in $3.3B Deal.)
ERCOT represents 15% of Dynegy’s capacity, which is dominated by PJM (43%). A combined Luminant and Dynegy would own almost 21.5 GW in ERCOT — about 45% of the company’s total — while reducing PJM’s share of the total to 29%.
Both Dynegy and Luminant have dealt with Chapter 11 bankruptcy in recent years. Dynegy filed and emerged from bankruptcy protection in 2012 after a failed takeover bid by private-equity firm Blackstone Group. Vistra is the new name for the generation and retail spinoff of Energy Future Holdings, which has been in bankruptcy court since 2014. (See TXU Energy, Luminant Rebrand as Vistra Energy.)
Vistra’s restructuring eliminated more than $33 billion in EFH debt, putting the company into a position where it could suggest an acquisition to Dynegy. According to the Journal, Vistra had only $4.5 billion in debt as of March.
Both companies also have retail businesses. Dynegy has about 963,000 residential customers in Illinois, Ohio and Pennsylvania, while Vistra’s TXU Energy provides energy to approximately 1.7 million residential and business customers in Texas’ deregulated market.
Vistra shares, which started trading on the New York Stock Exchange on May 11, dropped as low as $14.50 Friday but recovered to close at $15.04, down 21 cents (-1.4%). Dynegy shares opened Friday at $9.24 and finished at $9.12; the company’s stock has lost almost 75% in value since June 2014, when it stood at $36/share.
Meanwhile, shares of IPP Calpine, which owns 25,908 MW of generation, have risen by more than a third since the Journal reported May 10 that it was considering a sale.
NYISO’s Power Trends 2017 report shows an electric system of flat peak demand adapting under pressure from both public policy requirements and changes in consumption patterns. However, stark regional differences make the ISO “a tale of two grids,” CEO Brad Jones said in a media briefing on the annual report May 18.
“Not surprisingly, there are distinct differences between downstate and upstate in terms of power resources and consumer demand,” Jones said. “We have high demand and a concentration of fossil fuel generation downstate, while upstate has an abundance of clean energy resources and very low demand.”
The report, which is based on data from the ISO’s 2017 Load & Capacity Data report, or “Gold Book,” also highlights the emergence of distributed energy resources, which, in addition to serving the owners’ needs, can also provide benefits to the larger wholesale market.
The report forecasts peak demand in New York to grow at an annual average rate of 0.07% from 2017 through 2027, a decrease from the 0.83% annual growth projected in 2014 and the 0.21% predicted in 2016. Absent the impacts of energy-efficiency programs and DER, the 2017 peak demand growth rate is 0.73%.
Energy Efficiency and DER Change the Grid
The report projects energy efficiency will reduce New York’s peak demand by 230 MW in 2017 and by 1,721 MW in 2027 with annual energy usage cut by 1,330 GWh in 2017 and 2,533 GWh in 2027.
| NYISO 2017 Power Trends Report
NYISO projects distributed solar resources in New York to reduce peak demand by 450 MW in 2017 and by 1,176 MW in 2027, and to lower annual energy usage by 1,845 GWh in 2017 and by 5,324 GWh in 2027. Other behind-the-meter resources may reduce peak demand by 233 MW in 2017 and by 375 MW in 2027, while possibly cutting annual energy usage by 1,584 GWh in 2017.
Pricing Carbon to Reduce Emissions
Jones said that at FERC’s May 1-2 technical conference on how to integrate state policy with wholesale electric markets, “there was a consensus that did emerge at times from the diverse interests [on] the need to price carbon in the wholesale markets.”
“This is good news, as we have already been looking at that very issue,” Jones said. “A study is underway … and the Public Service Commission and the [Department of Environmental Conservation] have both expressed a willingness to consider those options with us.” (See Carbon Adder to Test FERC’s Independence, IPPNY Panelists Say.)
Since 2000, private power producers and public power authorities have added 11,733 MW of new generating capacity in New York, or approximately 30% of the state’s current generation. The report says more than 80% of that new generation is in southern and eastern New York, where power demand is greatest.
| NYISO 2017 Power Trends Report
Jones said New York’s wholesale market design, which includes locational-based pricing and regional capacity requirements, is encouraging investment in areas where the demand for electricity is highest. He also said that energy efficiency and market improvements have saved $7.8 billion in New York since 2000.
Divide Between Assessment and Planning
NYISO Executive Vice President Richard Dewey took over the report briefing for Jones, who had to leave. RTO Insider asked Dewey about recommendations to improve NYISO’s energy market made the previous day by the grid operator’s Market Monitoring Unit while presenting the 2016 State of the Market report to the Business Issues Committee. (See Gas Price Spreads Made NYC Generation More Economic in 2016.)
In suggesting improvements, how closely had the MMU worked with The Brattle Group, which is conducting the carbon-pricing study referred to by Jones?
“David Patton’s [of Potomac Economics and head of the MMU] responsibilities under our Tariff and what he’s attempting to provide in a State of the Market report is essentially an economic assessment of the market functions themselves and how efficiently they’re working, how effective they are and how fair they are,” Dewey said. “It’s less about a forward projection of other forces that might cause us to want to upgrade either the rules within our market or how we operate the grid. It’s probably premature right now to have a tight intersection between the State of the Market that David Patton does and some of this forward-looking work.”
NextEra Energy’s bid to acquire Texas utility Oncor has failed to gain traction with state regulators, who said Thursday they have not changed their minds about rejecting the Florida company’s purchase.
The Public Utility Commission briefly considered NextEra’s request for a rehearing before deciding to postpone final action until it meets on June 7, allowing time to review reply briefs due May 23.
“I haven’t changed my decision on their motion,” said Commissioner Brandy Marty Marquez, saying she would keep an “open mind” pending the reply briefs.
“I, too, remain unpersuaded at the time by their substantive arguments,” Commissioner Ken Anderson said. “I’m inclined to believe our original decision was the correct one.”
The PUC rejected NextEra’s $18.7 billion proposal last month, finding the acquisition not to be in the public interest because the risks outweighed the promised benefits. NextEra argued the commission went beyond the scope of its powers and called the PUC’s order “unprecedented,” asking it for additional time to review the case (Docket 46238). (See NextEra’s Rejected Oncor Bid Gets Second Look.)
Anderson said after reviewing NextEra’s arguments and an amicus brief filed by Oncor’s bankrupt parent, Energy Future Holdings, he was convinced the PUC has jurisdiction over the transaction and that NextEra was “legally required to seek our prior approval for the transaction.”
“I see no compelling reason to further delay these proceedings beyond what’s absolutely necessary,” Anderson said.
The commissioner asked staff to prepare an order clarifying some of the provisions in the original order and address the technical errors NextEra pointed to in requesting a rehearing. That order would be adopted June 7, should the PUC not grant a rehearing.
NextEra is liable for a $275 million termination fee should the deal fail for certain reasons.
The PUC last year rejected a previous attempt to acquire Oncor by Dallas-based Hunt Consolidated. Oncor’s future is central to EFH’s bid to exit Chapter 11 bankruptcy, which has now dragged on for three years.
New York hedge fund Elliott Management, a top creditor in EFH, sued the ownership group May 11. The firm said NextEra’s bid for Oncor is unlikely to close, and it requested the bankruptcy court to allow it to propose interim financing and alternative restructuring plans for EFH.
The meeting was the PUC’s first without Donna Nelson, who retired from the commission May 15. Texas Gov. Greg Abbott has yet to announce a replacement, leaving Anderson and Marquez to operate without a chairman.
The Conservation Law Foundation last week asked ISO-NE to override its member states and conduct a study to determine transmission needs driven by state renewable energy and carbon reduction policies.
In a letter May 16, CLF Senior Attorney David Ismay criticized a May 1 submission from the New England States Committee on Electricity as “legally insufficient for purposes of the regional system planning determinations that [FERC] Order 1000 requires.”
NESCOE concluded that there are no state or federal public policy requirements (PPRs) “driving transmission needs relating to the New England transmission system.”
Ismay argued that the NESCOE submission provided “no regional analysis, no discussion of the Regional System Plan process or timing, and no discussion of the regional impact that stakeholder-identified PPRs are likely to have collectively on regional transmission between 2018 and 2027, the relevant regional planning period.”
ISO-NE asked for comments on state, federal and local PPRs driving transmission needs in January. Responding, in addition to NESCOE and CLF, were Avangrid, National Grid, NextEra Energy Transmission and TDI-New England, all of which called for the RTO to conduct a study. (See ISO-NE Begins Discussing Order 1000 Public Policy Tx Projects.)
States: No Current Public Policy Tx Needs
NESCOE’s response, which dismissed the companies’ rationale, was accompanied by memos from each of the states, none of which called for a study.
Connecticut, for example, noted that two recent solicitations for renewable energy and demand response resulted in the selection of nine projects, none of them involving transmission. It also said it was meeting its greenhouse gas reduction targets and that while “far deeper cuts” will be needed to meet the 2050 target — 80% below 2001 levels — no new transmission is currently required.
The Massachusetts Department of Public Utilities acknowledged that the state’s requirement that electric distribution companies sign long-term contracts for 9.45 million MWh of clean energy annually by 2022 and 1,600 MW of offshore wind generation by 2027 “may drive the need for transmission infrastructure in the future.”
| ISO-NE
“However, because we presently lack clarity regarding the outcome of the solicitations and any projects that may result from the … solicitations, we find it inappropriate to request a public policy transmission study at this time,” the state said.
Rhode Island said its electric retailers are meeting the state’s renewable energy standard, which requires them to obtain 11.5% of power from renewable sources in 2017, without the need for new transmission. Although the standard rises to 38.5% by 2035, the state said “local renewable distributed generation resources are projected to produce a substantial quantity of [renewable energy certificates] in the coming years, regardless of actual or perceived regional transmission needs.”
Vermont said that its “statutes and policies not only do not drive transmission needs, but rather endeavor to avoid the need for increased transmission. The reason for this policy is to protect ratepayers from the significant costs of building new transmission projects where the particular need can be served more economically by a non-transmission alternative.”
Ismay wrote that the “NESCOE submission simply forwards to ISO-NE individual state-centric analyses by each of the six New England states, all of which expressly disclaim or avoid the type of long-range regional assessment Order 1000 requires.”
Court Rebuff of NESCOE
Ismay said a D.C. Circuit Court of Appeals ruling in April confirmed the responsibility of ISO-NE, “not the states, to evaluate transmission needs and potential solutions as part of its Regional System Plan process, regardless of whether those transmission needs arise from state public policy requirements or any other source” (Emera Maine v. FERC, No. 15-1139). (See Court Rebuffs New England TOs, Upholds FERC ROFR Order.)
| ISO-NE
The court rejected NESCOE’s claim that FERC’s ISO-NE compliance order went beyond Order 1000 and “impermissibly altered the balance of responsibility and power” between the states and the RTO.
“ISO-NE has no role in setting public policy for the states,” the court said. “ISO-NE considers transmission needs that arise from a variety of sources, one of which is the public policy requirements chosen by federal and state officials.”
Ismay asserted in his letter that “ISO-NE itself has already repeatedly recognized” that transmission will likely be needed to deliver new renewable and low-carbon resources required to meet the carbon emission reduction goals of Connecticut and Massachusetts. He cited the grid operator’s January 2017 Regional Electricity Outlook, which stated that “connecting additional remote clean-energy resources is also going to require improvements on the transmission system.”
ISO-NE Director of Transmission Planning Brent Oberlin provided a status report on the RTO’s transmission planning evaluations during a conference call Friday of the Interregional Planning Stakeholder Advisory Committee for New England, NYISO and PJM.
“If the ISO decides that we will be moving forward with a public policy transmission study, we need to provide a scope to stakeholders by Sept. 1,” Oberlin said. “We do plan on having some discussion on the ISO’s going-forward plan at our June Planning Advisory Committee meeting.”
