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.”
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.
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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.
