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.”
RENSSELAER, N.Y. — Significant natural gas price spreads between Western and Eastern New York in 2016 led to New York City generation being “more economic than in recent years,” Pallas LeeVanSchaick of Potomac Economics, director of NYISO’s Market Monitoring Unit, told the ISO’s Business Issues Committee on May 17.
In presenting the 2016 State of the Market report, LeeVanSchaick said natural gas prices on the Transco Zone 6 pipeline, serving New York City, averaged $2.19/MMBtu, roughly halfway between Millennium Pipeline’s $1.46/MMBtu and Iroquois Zone 2 at $2.84/MMBtu.
Enhancing the Energy Market
The report makes several recommendations to enhance energy market performance, primarily to real-time market operations and capacity pricing. The real-time change would be to consider rules that would adequately compensate all resources that relieve congestion while factoring in performance and the marginal cost of maintaining reliability.
| Potomac Economics
LeeVanSchaick said 92% of real-time congestion on 345-kV lines into the city occurred when reserve units were not believed to be available.
The report also recommends implementing location-based marginal cost pricing of capacity, which would save tens of millions annually and reduce volatility of prices and requirements.
Looking Forward
On long-term investment signals, LeeVanSchaick said the MMU does not estimate new environmental costs going forward, such as dramatic changes in Regional Greenhouse Gas Initiative costs. “We use price tails, old CAPEX [capital expenditures],” he said, repeatedly telling market participants that the report was based on publicly available data.
| Potomac Economics
LeeVanSchaick was questioned on renewable forecasts that show a higher-than-market $240/MW cost of new entry for offshore wind off Long Island. LeeVanSchaick said the CONE assumed a 30-mile cable; a project closer to shore would reduce the projected estimate. The report also assumes for generators a “modest recovery of revenues going forward,” based on forward prices.
Deficiencies in New Zone Creation Process
The report says that while the new capacity zone for the G-J Locality in Southeast New York (SENY) has greatly enhanced the efficiency of capacity market signals, the new zone took years to create after it was first needed. This delay saw capacity in Zones G, H and I fall by 21% from 2006 to 2013, even as the need for resources in the SENY interface became more apparent.
One problem with the process is it being based on the highway deliverability test criterion, which ignores the reliability issue that would justify the creation of a new capacity zone. This can lead to additional capacity being procured on the constrained side of a transmission bottleneck to meet the reliability needs of the load pocket. For example, a 1% increase in the local capacity requirements equated to a $1.30/kW-month increase in capacity prices given the 2013/14 demand curve for New York City.
The report cites the retirement of the Indian Point nuclear plant as a “salient example” of the problems that can arise from the shortcomings in the new zone creation process. If Indian Point retires in 2021, and it leads to resource adequacy violations for Eastern New York or the area south of the Upstate NY-Con Ed interface, the “process would not consider creating an additional zone for any time before 2025. In fact, it would not trigger the creation of a new zone at all if there are no highway deliverability constraints.”
The report recommends NYISO adopt “a dynamic framework where potential deliverability and resource adequacy constraints are used to pre-define a set of capacity interfaces and/or zones.”
CARMEL, Ind. — MISO has made two changes to its newest future scenario in its annual Transmission Expansion Plan, adding more renewables and possible nuclear retirements to capture distributed energy trends and distinguish them from a continued fleet future.
The RTO bumped up the renewable target on its distributed and emerging technologies future from 15% to 20% of total MISO energy by 2032, policy studies engineer Matt Ellis told stakeholders at the May 17 Planning Advisory Committee meeting. He said MISO plans to model a more aggressive solar maturity curve for the future in response to stakeholder requests for more solar additions in the model. The RTO will assume that in 15 years, two-thirds of all solar is distributed and located near the top 20 load buses in each local balancing authority. MISO’s three other MTEP 18 futures assume one-third of all solar is distributed.
Shelly-Ann Maye, representing Midwest Power Transmission Arkansas, asked how MISO settled on 20% renewable penetration in the fourth future.
Ellis explained that it examined projects lined up in the interconnection queue. “Renewable targets vary state by state, and [at] a bare minimum, our models will capture that, and that’s about 10% in the limited fleet change [future]. Historically, though, we find that renewables go beyond those renewable standards.”
Citing DTE Energy’s recent announcement that it intends to reduce its carbon output by 80% by 2040, ITC Holdings’ David Grover asked if MISO considered more aggressive low-carbon generation addition trends in the futures.
“If you look at goals that are announced and goals that are out there from large utilities, what’s the base? Are you starting from the base [fleet] or from what utilities have said that they’re going to do?” Grover asked.
Ellis said carbon-reduction modeling begins from the current fleet and carbon emission levels. “As these press releases come out, this is something we can look at,” Ellis said.
MISO will also now assume a top end of 5 GW of nuclear retirements in the distributed future, through the assumption that nuclear licenses renewals will not be granted unless the plant had a “recent and significant update.” It is the only future that will model possible nuclear retirements; the other three futures assume that the zero-emission reactors will continue running.
Some stakeholders asked if MISO considered that unprofitable nuclear plants will continue to be offered subsidies through state legislation. “I think it’s implicitly assumed, not explicitly assumed. That’s why we’re modeling anywhere from zero to 5 GW” of retirements, Ellis said.
Stakeholders had asked how the distributed and emerging technologies future differed from MISO’s continued fleet change, which originally predicted similar renewable penetrations, demand-side additions and coal generation retirements. (See MISO Introduces Distributed Energy Future for 2018 Tx Planning.) Ellis said the siting of resources is the main difference between the two futures. “It’s more distributed, more local to load.”
The distributed and emerging technologies future also includes the addition of 2 GW of storage by 2032 and the assumption that 25% of all new car sales by 2032 are electric vehicles — driving up MISO load by 60 TWh in 2032.
Though the MTEP 18 futures are still technically a proposal, and stakeholders have until June 1 to provide comments, Ellis said he does not expect details to change much before the final future definitions are revealed at the June PAC meeting. MISO will also discuss MTEP 18 futures weighting at the June meeting, with the RTO unveiling some weighting “process reforms,” he said.
At the January PAC meeting, some stakeholders, especially those hailing from MISO South, argued that the Trump administration’s distaste for carbon regulations should influence the RTO’s weighting process. As a result, MISO placed less emphasis on its accelerated alternative technologies future in the South region’s market congestion planning study. (See MISO Changes MTEP Futures Weighting for South.)
MISO: Non-Tx Alternatives in Tx Planning Process by Late Summer
MISO is moving to include non-transmission alternatives in Business Practices Manual 020, which governs transmission planning procedures.
Adviser Matt Tackett said staff will not adopt the BPM language until the PAC makes an official recommendation, expected at the June meeting. He added that stakeholders had not suggested any significant changes in the last round of feedback.
The revision dictates that “both transmission and non-transmission alternatives to resolve transmission issues will be considered on a comparable basis” in MTEP cycles. MISO said non-transmission alternatives can include “contracted demand response, new or upgraded generators with executed interconnection agreements and other non-transmission assets (e.g., energy storage not classified as a transmission asset, etc.).” (See “Rules on Non-Transmission Alternatives Ready for PAC Review,” MISO Planning Subcommittee Briefs.)
MISO’s process for considering non-transmission alternatives involves:
an evaluation of the transmission need; flagging constraints that cannot be adequately addressed by non-transmission alternatives;
conducting analyses to find the best bus location or amounts of injections or withdrawals of real or reactive power that would resolve the issue;
determining minimum project requirements; and
performing a final analysis to determine if a proposed non-transmission project solves the problem.
MISO expects the updated BPM to become effective Aug. 1.
MISO Fields Another Expedited Review Request
MISO has received a new expedited project review request to connect load from a northern Michigan steel mill to a member ahead of the MTEP timetable.
Wolverine Power Supply Cooperative plans to connect 24.4 MW of industrial load from a nearby steel mill, a blend of induction furnace and plant auxiliary system load, to its Advance-Van Tyle 138-kV transmission line at a cost of $6.15 million.
The cooperative estimates that transmission structures need to be ordered by the end of August to meet a promised March 1, 2018, in-service date, making the regularly scheduled December Board of Directors decision date for MTEP too late, Manager of Transmission Expansion Planning Thompson Adu said.
Adu said MISO has also received another expedited project review request from a Michigan market participant, as well as two requests from companies in MISO South, but they have not yet been posted publicly, as the RTO is still reviewing the requests.
RENSSELAER, N.Y. — NYISO reported Wednesday that natural gas prices rose 73% in April year-on-year but were still “historically low.” Natural gas (Transco Z6 NY) in April cost $2.81/MMBtu, down from $3.49/MMBtu in March.
In his Market Operations Report to the Business Issues Committee, Rana Mukerji, senior vice president for market structures, reported an average year-to-date cost in April of $37.05/MWh, up 21% from $30.71/MWh in April 2016. Locational-based marginal pricing (LBMP) for April came in at $31.06/MWh; down from $34.97/MWh in March 2017 and higher than $27.96/MWh in April 2016.
| NYISO
Generation averaged 377 GWh/day in April, down from 419 GWh/day in March 2017 and 385 GWh/day in April 2016.
April distillate prices came in higher compared to the previous month and up 29.5% year-on-year, with Jet Kerosene Gulf Coast at $11.15/MMBtu, up from $10.69/MMBtu in March, and Ultra Low Sulfur No. 2 Diesel NY Harbor at $11.31/MMBtu, up from $10.90/MMBtu. Uplift rose in April to 12 cents/MWh (excluding NYISO cost of operations), higher than the 46 cents/MWh in March. The local reliability share was 20 cents/MWh, lower than 21 cents/MWh in March, and the statewide share was -8 cents/MWh, higher than the -67 cents/MWh in March. Total uplift costs with Schedule 1 components, including NYISO cost of operations, were higher than in March.
MISO Refunds Paid out to TOs
Ramapo Phase Angle Regulator | ConEd
Mukerji also presented NYISO’s monthly Broader Regional Markets Report, highlighting that the grid operator in May completed paying refunds totaling $16.3 million and $1.27 million in interest to transmission owners for the Michigan-Ontario phase angle regulator. FERC last September rejected a MISO/ITC Holdings proposal to allocate 30.9% of the cost of ITC’s Michigan-Ontario PARs to New York, ruling in favor of NYISO and PJM. NYISO received the refund payment from MISO. (See MISO not Allowed to Allocate Lake Erie PARs Costs to PJM and NYISO.)
NYISO Complies with FERC Order 831
The ISO submitted an Order 831 compliance filing to FERC on May 8. The commission’s November 2016 order requires NYISO to 1) cap each resource’s incremental energy offer at the higher of $1,000/MWh or its verified cost-based incremental energy offer, and 2) to cap verified cost-based incremental energy offers at $2,000/MWh when calculating LBMPs.
Con Ed-PSEG Wheel Enters New Protocol
NYISO and PJM this month implemented a new protocol for the Con Ed-PSEG “wheel” to replace the agreement that expired after Consolidated Edison chose not to renew the contracts for the wheel. NYISO and PJM filed jointly with FERC on Jan. 31. FERC accepted the NYISO-PJM filing effective May 1, subject to refund and further FERC order. (See NYISO Members OK End to Con Ed-PSEG Wheel.)
Con Ed Gets Approval to Install 2nd PAR at Ramapo
The committee voted to recommend Management Committee approval of a tariff modification to fund Con Ed’s replacement and operation of the Ramapo PAR #3500, destroyed in a fire last June. Con Ed, though opposed to what it sees as cumbersome Tariff and rate schedule filings, pledged to complete installation of the second PAR by early fall 2017.
The cost allocation is statewide across all New York load-serving entities, but the proposed rules would reimburse the LSEs with any monies eventually paid by PJM and its TOs, or refunded by Con Ed. Contingent on approval by the Management Committee, the Board of Directors would vote on the proposal in June or July. (See NYISO, PJM Discuss PARs’ Benefits, Cost Allocation.)
NYISO to Eliminate Bond Fund Options
The BIC also voted to recommend Management Committee approval of a proposal to eliminate the bond fund options as an alternative to cash collateral. Sheri Prevratil, manager of corporate credit, said that historically there has been very low market participant use of the bond funds — on average, only $500,000, or 0.17%, of total cash collateral has been invested.
No other ISO/RTO offers bond funds for cash collateral investments. If the NYISO board approves it, the measure would be filed under Section 205 of the Federal Power Act, with revisions to Attachment K of the Market Administration and Control Area Services Tariff and Attachments U and V of the Open Access Transmission Tariff.
CHICAGO — The PJM Annual Meeting marked the swan song for longtime consumer advocate Dan Griffiths, executive director of the Consumer Advocates of the PJM States.
PJM officials and stakeholders feted Griffiths on Monday at the annual meeting between the PJM Board of Managers, environmental groups and state consumer advocates. Griffiths, who became CAPS’ first executive director in September 2013, is being replaced by Greg Poulos, former director of regulatory affairs for demand response provider EnerNOC. (See CAPS Hires EnerNOC Alum as Executive Director.)
PJM CEO Andy Ott called Griffiths “a tremendous friend for many years.”
“Thank you very much for all you’ve done to bring CAPS to a level that it’s at,” he said. “The fact that there’s 22 [consumer advocates] here discussing these issues is a tremendous message of engagement. The desired outcome of these discussions is to make sure we understand each other, to communicate with each other and we move forward in a cooperative way.”
Griffiths responded with praise for the PJM stakeholder process. “The collegiality — even for people that I almost always disagree with — is fantastic,” he said. “I have never seen this anywhere else.”
Metrics
Griffiths started his career in 1979 at the Pennsylvania Public Utility Commission, developing metrics for utilities’ consumer services performance. He began specializing in electricity after restructuring in 1997, with several stints in private industry before returning to state government in 2000 as an assistant under then-Consumer Advocate Sonny Popowsky, a vacancy created when predecessor Denise Foster joined PJM. He retired from state government at the end of the Ed Rendell administration in 2010 as a deputy secretary of the Department of Environmental Protection’s Office of Energy and Technology Deployment.
He later served as DR provider Comverge’s delegate to the PJM stakeholder process. He was in that role when the newly formed CAPS selected him as its first executive director, using proceeds from Constellation Energy’s settlement with FERC in a market manipulation case. (See Consumer Advocates Name Director.)
Griffiths said the idea for CAPS began with conversations among him, Popowsky, West Virginia Public Advocate Jackie Roberts and Maryland Senior Assistant People’s Counsel Bill Fields.
CAPS’ biggest accomplishment during his tenure was helping state consumer advocates become engaged in PJM’s stakeholder process, he said in an interview at the Annual Meeting on May 15. “The first purpose was to make them understanding enough so that they could make decisions, so that they could vote in the stakeholder process … and be able to make thoughtful filings as opposed to ‘just say no’ filings.”
The engagement has been illustrated in the recent Capacity Construct/Public Policy Senior Task Force (CCPPSTF), he said.
“We had a one-hour meeting today to discuss it. We’ve probably had eight hours of phone calls … over the past several months to talk about it,” he said. “The CAPS members — the state consumer advocates — really do have a drive to understand the policy now and be part of creating, rather than reacting to it.”
Permanent Funding
The Constellation money would have run out next year, so PJM’s decision to provide permanent funding — via a bill surcharge similar to that used to fund the state regulators’ Organization of PJM States Inc. — was crucial to its future.
FERC approved an initial annual budget of $450,000 in 2016. In addition to paying for the executive director, the funding also is used to cover advocates’ travel to PJM meetings. (See FERC Approves PJM Funding of Consumer Advocates.)
“We have ongoing funding and we’ve got [an] executive director who is outstanding: creative, ambitious, excellent in outreach and coalition building … and articulate,” Griffiths said. “And so I think that CAPS will be better after me. I think I’m leaving at the right time.”
Griffiths said the 13 states (and D.C.) in CAPS understand the impact of PJM on their customers’ electric bills.
“They wouldn’t be here if their [state] offices didn’t make a decision to dedicate resources to the PJM process. I think everybody understands now just how important that is. In a competitive state like Pennsylvania, you might have 70% of your electric bill that comes through the PJM process. You cannot mitigate that by doing things at the state level, no matter how much you want to. And even in … [vertically integrated] West Virginia, 50% of their process is coming through the PJM process.”
“Pennsylvania uses … about 138 million MWh. [Actually more than 146 million MWh in 2015, according to the PUC.] And if the pricing is [increased] by a buck, that’s a $138 million hit to the Pennsylvania economy. … There are Market Monitors out there who think a few bucks here or there is like, ‘Okay, that’s fine.’
“It’s not fine,” Griffiths continued. “Consumers are hurt even by small pricing errors, and so it’s important for [Independent Market Monitor] Joe Bowring to be able to continue to do his job and PJM to be vigilant about making sure that the prices are right. There’s people [on the supply side] who have a natural incentive — they have a fiduciary responsibility — to make prices go up.”
Asked what advice he had given Poulos, Griffiths responded: “There’s all these pieces [that] work together. You cannot just [focus on] the markets because it seems like that’s where [the money] is. If you have a [load] forecast that’s one level and it could be 2.5% less — as we found over the last couple of years as PJM changed its forecasting process —that’s 2.5% of a whole lot of money. You can’t neglect any of this stuff because the scale is so huge and it interacts. Energy market performance affects capacity, offer caps. And so it just keeps rolling along.”
Going Solo
Poulos, who previously worked as an assistant in the Office of the Ohio Consumers’ Counsel, has been working for CAPS under Griffiths since the OPSI annual meeting in April. So is he ready to go it alone?
“Absolutely not,” he laughed during an interview Wednesday, describing the last several weeks of Griffiths’ tutelage as “drinking from a firehose.”
“But I’m in a really good position. He was so helpful with all the information. He has such a wealth of knowledge, even about the stakeholder process.”
“He was a true champion for consumers. That is very clear. He’s done a great job of advocating on behalf of the advocates and consumers. At the same time, he was a true friend and colleague to all [in the stakeholder process],” Poulos continued. He taught “the value of being a part of the community and making sure you participate and get to know everybody.”
On some issues, such as the cost and transparency of transmission expansion projects, CAPS is likely to have a unified position. But Poulos said there are times when his role will be less a lobbyist than a facilitator, providing information for individual state advocates.
In preparing for FERC’s May 1-2 technical conference on tensions between state actions and wholesale markets, “it was very clear that we at CAPS did not have a position and could not have a position,” he said. Some advocates “wanted to [accommodate] state actions and others want a true market where state actions aren’t considered.”
Off to Europe
Griffiths left the annual meeting early Tuesday to begin a month-long trip to Austria, Switzerland and Italy with his wife, Maureen Mulligan, a retired solar energy and energy-efficiency activist.
He hasn’t closed the door to returning to the industry in some fashion but has no plans. “I cannot come back here and work for anybody on the supply side … because their interests are so different than [consumers] and I think people … would think I was being hypocritical,” he said.
“I talked to folks a little bit about [doing] things outside PJM but I’m not dying to travel. I’ve done a lot of travel in my years. You know, after a while there’s no glory in travel. It’s just the torture you go through to do your job.”
Reforms to CAISO’s congestion revenue rights auctions will come only after painstaking analysis of what is causing the auctions to pay out significantly more money than they take in as revenue, the ISO official leading the effort told stakeholders Tuesday.
“We really want to lay down what’s going on and understand the dynamics of the auction,” Guillermo Bautista Alderete, CAISO director of market analysis and forecasting, said during a May 16 Market Performance and Planning Forum. “We want to understand what are the drivers [of revenue shortfalls] and have an informed set of data that can guide us into what the policy’s going to be.”
Any policy changes are likely to prove contentious among market participants with a stake in the auctions.
The CAISO Department of Market Monitoring insists that the ISO-sponsored auctions should be replaced with a bilateral market that doesn’t leave utility ratepayers as unwilling counterparties in losing deals.
On the other side stand the Western Power Trading Forum and DC Energy — a firm specializing in trading CRRs and other financial instruments tied to power and natural gas markets — which argue that the auctions provide the only liquid market for hedging congestion risk in the ISO’s wholesale market.
Most stakeholders, including the ISO’s load-serving entities, sit somewhere in the middle of the debate but tend to agree the auctions require significant changes, if not dissolution.
CAISO is seeking to understand why the ISO’s congestion revenue rights auctions have been a consistent money-loser for California ratepayers. | CAISO Department of Market Monitoring
Bautista Alderete said the CAISO plan for examining the CRR auctions was shaped by suggestions coming out of an April 18 working group convened to kick off the initiative. (See Heated Start for CAISO CRR Reform Initiative.)
The analysis phase will begin with ISO staff picking off the “low-hanging fruit” to be found in the auction results: “Profits, losses, who’s losing, who’s winning over time [and outcomes of] the annual [auction] versus the monthly,” Bautista Alderete said.
A second, “more complex” phase will look at how various auctions were modeled and compare that information to how the transmission system was modeled in the day-ahead markets on which CRR payments are settled. That will require an accounting of transmission outages, and whether they were included in auction models.
“These types of metrics are not that simple” to produce, Bautista Alderete said.
A third, “most complicated” phase will delve into the transmission system constraint by constraint, focusing on those constraints that did not bind (or show high congestion) in the auctions but paid out to CRR holders in the day-ahead market, as well as constraints responsible for the largest payouts.
“That is the type of analysis that we want to take on to understand the efficiency of the auction, because once we can understand what is behind the specific divergence between day-ahead and [the auctions] — the specific driver for revenue insufficiency — we can really start putting the pieces together for why we landed there, [for] why we have a systemic constraint that is always on the winning side or the losing side,” Bautista Alderete said.
In order for the findings to be “meaningful,” he added, the ISO must undertake a time-consuming process of examining constraint data going back to the start of the auctions, which will include determining how nomograms modeled in the CRR auctions may have changed in the corresponding day-ahead market.
Bautista Alderete expects the first round of “straightforward” data analysis related to auction results and settlements to be complete in two months. He provided no timeline for the other two phases.
“Once we complete the analysis phase, then we’re going to start moving into the discussion of the policy — what we need to do. Do we need to scrap the auction? Do we need to tweak the auction? That is the piece we need to reach only when we have determined, based on the analysis, what we need to do.”
It typically takes “two or three or four things” to occur for CAISO declare a grid emergency, according to Tim Beach, an operations shift manager with the ISO.
“Which is what played out here on May 3,” Beach said during a May 16 Market Performance and Planning Forum, at which he recounted why CAISO on that day declared its first Stage 1 emergency in 10 years.
The causes on this day: high temperatures, a generator failure, no-show imports and a rebuff from suppliers.
Although May 3 was forecast to be one of the warmest days of the year to date, it was considered a day with “pretty normal” conditions, Beach said. Los Angeles area temperatures ranged from the mid-80s downtown to the mid-90s farther inland and to the north.
System loads began to diverge from day-ahead forecasts about 1 p.m. “That’s not unusual,” Beach said. “We typically see a lot of that. We’ll see it diverge and we’ll also see it come back and converge again at peak or after peak.”
About 10 minutes later, a 330-MW unit at AES’ gas-fired Alamitos generating station in Long Beach shut down unexpectedly, taking with it 270 MW of energy production that had been awarded in the day-ahead market.
The unexpected shutdown of one unit at AES’s Alamitos generation station was one of a handful of events that precipitated CAISO’s May 3 “Stage 1” emergency. | California Energy Commission
Still, conditions remained normal throughout the afternoon, and the ISO was carrying ample reserves by the time load peaked at 5:45 p.m.
No Shows
But a short time later, about 1,150 MW of imports scheduled in the day-ahead market didn’t materialize. The hour-ahead market then awarded 1,230 MW of supplemental energy on the interties for the hour ending 8 p.m. But about 830 MW of the awards were declined by the suppliers.
“So going into hour ending [8 p.m.], we’re over the peak. We’ve got solar ramping off very quickly. It’s starting to look pretty tight,” Beach said.
At 6:42 p.m., with solar quickly coming off the system, the shift manager on duty began canvassing the utilities for available DR.
“That’s a typical procedure we do,” Beach said. “We go out and look and make sure we have a number that we can operate to.”
Within 15 minutes, the shift manager determined that the ISO’s area control error — the difference between actual and scheduled generation — was at 750 MW. With solar continuing to roll off the system, the manager was forced to deploy reserves, which then fell to about two-thirds of the 1,870-MW requirement.
Emergency Declared; DR Called
About 7 p.m., CAISO declared the Stage 1 emergency, simultaneously calling for 843 MW of DR from the utilities.
“And at [7:34 p.m.], with the DR deployed, our ACE was up to 34 MW on the plus side,” Beach said. “So we recovered briefly, but solar is still ramping off — but the load’s ramping off at the same time.”
By 8 p.m. the situation had stabilized. The ISO called off the emergency an hour later.
Brian Theaker, director of market affairs at NRG Energy, asked how much of the 843 MW of DR deployed by the ISO actually responded to the dispatch call.
“I can’t establish that at this time,” Beach said. “I think the market analysis [will provide] the exact number or a close number. We’ll rely on some of that to come from the utilities as well.”
Wei Zhou, senior project manager at Southern California Edison, asked whether transfers from the Western Energy Imbalance Market (EIM) assisted during the event.
“There were about 500 MW of transfers around that time, so it was helping us,” said Guillermo Bautista Alderete, CAISO director of market analysis and forecasting.
Why the Rejections?
Bautista Alderete was unable to address a question about exactly why suppliers on the interties declined the 8,300 MW of awards ahead of the event. Such declines are not unusual, but “not to this level, not to this volume,” he responded.
“This is somehow an action that [suppliers] can take and this is something we have to discuss further as to how we can enhance the procedure that we have,” Bautista Alderete said. “Because usually you don’t want to see them decline when you need that [energy] most.”
“Was it a lot of different entities that made up the 830 [MW of declines] or was it just a few?” asked Carolyn Kehrein, a consultant for Energy Users Forum.
“I would love to give you an answer on that,” Bautista Alderete said. “We haven’t completed the full analysis, so I would like to hold off on that answer.”
