MISO’s plan to create external resource zones in its annual capacity auction isn’t detailed enough on several fronts, FERC told the RTO on Wednesday.
Commission staff issued MISO a deficiency notice explaining the proposal lacks sufficient detail about the reliability concerns that spurred it, the concept of border external resources, and how pseudo-tied resources and coordinating members’ resources will factor into the proposal (ER18-1173).
MISO filed the plan in late March after three years of stakeholder meetings in its Resource Adequacy Subcommittee. It would create external resource zones by 2019 for MISO’s annual capacity auction, based on existing neighboring balancing authority area boundaries. External zones would not have capacity import limits, planning reserve margin requirements or local clearing requirements.
Resources in BAAs that border either MISO Midwest or South would clear at two different prices based on subregional unconstrained auction clearing prices, while those in BAAs that border both MISO areas — including Tennessee Valley Authority, SPP, Associated Electric Cooperative Inc. and Southwestern Power Administration — would receive a blended price.
| MISO
In cases of auction price separation, the RTO would distribute historical supply arrangement credits from excess auction revenues as a refund to external resources with long-term and consistently used historical supply agreements. The proposal would also establish new zonal capacity export limits in time for the 2019/20 planning year auction. (See MISO Closing in on External Capacity Zones.)
In its deficiency letter, FERC asked MISO, among other questions:
Why it thinks that its current practice of giving external resources capacity credit in the local resource zone where its firm transmission service crosses into the footprint has the potential to cause reliability concerns;
How it will reconcile its current Tariff definition of local clearing requirement — defined as the minimum amount of unforced capacity physically located with a local zone — with its proposal to allow certain external resources to contribute to a local resource zone’s local clearing requirement;
If it will count pseudo-tied resources as external resources;
How it differentiates a “border external resource” — defined in the proposal as resources with direct electrical connections to the RTO but located in another BAA — from all other external resources;
How border external resources and coordinating owner external resources can be used to alleviate transmission constraints and address other reliability concerns for local resource zones;
How it plans to model external resources and how coordinating owner and border external resources will impact capacity import and export limits;
What physical and operational standards a coordinating owner external resource must meet to qualify for capacity credit in a local resource zone. FERC also asked MISO to identify any other coordinating members besides Manitoba Hydro, its sole listed coordinating owner;
If its proposed historical supply arrangement credits will be distributed to resources offered into the Planning Resource Auction, resources included in a fixed resource adequacy plan or both; and
How much estimated capacity would qualify for historical supply arrangement credits. FERC also asked MISO to describe scenarios in which the credits might not be fully funded.
FERC also ordered MISO to list all resources that would receive border external resource designation, their unforced capacity values and the local resource zones they border. The RTO previously said it identified about 3.8 GW of capacity from potential border external resources.
Finally, the commission said MISO must compare in writing the operational control it has over Manitoba Hydro’s resources versus other external resources, including Exelon’s Byron Generating Station, Duke Energy Indiana’s Madison Generating Station, WPPI Energy’s Nelson Energy Center and any resources with firm transmission service over a direct current line, such as the Grain Belt Express Clean Line.
FERC took another step Thursday in its efforts to protect the grid from geomagnetic disturbance events (GMDs), proposing to approve a revised reliability standard but directing NERC to also require mitigation of vulnerabilities to localized events (RM18-8).
The commission’s Notice of Proposed Rulemaking would approve reliability standard TPL-007-2 (Transmission System Planned Performance During Geomagnetic Disturbances), which revises the definition of GMDs, requires grid operators to collect certain data and imposes deadlines for corrective actions, as the commission directed in Order 830 in 2016. (See FERC Approves GMD Reliability Standard.)
GMDs occur when the sun ejects charged particles that cause changes in the earth’s magnetic fields, potentially causing geomagnetically induced currents that can cause voltage instability or collapse and damage connected equipment.
The rule would require planning coordinators and transmission planners to conduct supplemental GMD vulnerability and thermal impact assessments that go beyond NERC’s original “benchmark” GMD event definition that is based on spatially averaged data.
NERC defined the “supplemental” GMD event using individual station measurements rather than spatially averaged measurements, acknowledging that geomagnetic fields during severe GMD events can be “spatially non‐uniform” with localized peaks that could affect reliability.
The supplemental GMD event is defined by a “reference peak geoelectric field amplitude” of 12 V/km versus the 8 V/km used in the original spatially averaged definition. Both are intended to reflect a one-in-100-year occurrence and use scaling factors to account for local geomagnetic latitudes and earth conductivity. They also employ a “locally enhanced reference geomagnetic field time series or waveform” to analyze the impact of the GMD on equipment.
Mitigation Directive
NERC’s standard requires mitigation of vulnerabilities to the benchmark event, setting a one-year deadline for the completion of corrective action plans and two- and four-year deadlines to complete mitigation actions involving non-hardware and hardware mitigation, respectively.
But NERC rebuffed FERC’s call for mitigation of risks from supplemental events. NERC’s proposed standard would only require applicable entities to make “an evaluation of possible actions designed to reduce the likelihood or mitigate the consequences and adverse impacts of the event(s)” if a supplemental GMD event is assessed to result in cascading outages.
NERC told FERC that its standard drafting team determined that requiring corrective action plans in response to supplemental GMD event vulnerabilities was premature because the supplemental definition is based on small number of observed events “that provide only general insight into the geographic size of localized events during severe solar storms.” NERC also said current tools are inadequate to realistically model localized events.
But the commission said NERC’s position ignored its directives in 2013’s Order 779, which were reiterated in Order 830.
“NERC’s proposal to modify the benchmark, but then allow applicable entities the discretion to take corrective action based solely on the results of the spatially averaged benchmark analysis while taking under advisement (‘an evaluation of possible actions’) the results of the supplemental assessment, does not satisfy the clear intent of the commission’s directive. …
“We are not persuaded by NERC’s reasoning that … existing technical limitations, specifically the limited number of observations used to define the supplemental GMD event and the availability of modeling tools to assist entities in assessing vulnerabilities, make requiring mitigation premature at this time.”
Deadline Extensions
NERC also diverted from Order 830’s directive that it consider extensions of the corrective action deadlines on a case-by-case basis.
Instead, NERC would allow entities to unilaterally revise their corrective action plan if events beyond its control — such as delays from regulatory and stakeholder processes, equipment lead times or inability to acquire rights of way — prevent implementation within the original timetable.
“Given the complexities and potential novelty of steps applicable entities may take to mitigate the risks of GMDs, we agree with NERC that there should be a mechanism for allowing extensions of corrective action plan implementation deadlines,” FERC said. “However, we would like to avoid unnecessary delay in implementing protection against GMD threats.”
The NOPR seeks comment on whether the standard should permit these “self-declared extensions” or be revised to require NERC’s case-by-case approval. “Under either option, the commission proposes to direct NERC to submit a report regarding how often and why applicable entities are exceeding corrective action plan deadlines,” FERC said.
National Harbor, Md. — If, in the coming years, Howard Schneider feels an inexplicable urge to be at the Chase Center in Wilmington, Del., on Thursdays late in the month, he can be forgiven. PJM’s monthly Markets and Reliability/Members committee meetings have been part of his life for the past 21 years.
The first and only nonexecutive chairman of PJM’s Board of Managers retires Wednesday, having reached the limit on terms an individual can serve on the board. It’s a day for which he has had years to prepare, and yet he’s resigned to the fact that he may never be fully ready to let go. (See related story, PJM Board Elects New Chair, Welcomes New Member.)
“[It] is going to be a melancholy day,” Schneider said during an interview Tuesday at PJM’s annual meeting at the Gaylord National Resort & Convention Center on the Potomac River outside D.C. He was only half joking.
And why not? Schneider has been on the board since its inception in 1997 when, PJM — formed as a power pool run by Philadelphia Electric Co. and others in 1927 — completed its transition to an independent organization and became the nation’s first fully functioning independent system operator. He became the board’s first nonexecutive chairman in 2007.
Schneider was there as PJM became the nation’s first fully functioning RTO in 2002 and worked through many market changes since then. He has overseen two transitions of the executive team, from Phil Harris to Terry Boston in 2007 and from Boston to Andy Ott, PJM’s current president and CEO, in 2015.
“Phil was an innovator, very talented, a futuristic thinker,” Schneider said. “Terry was a practical guy who implemented well and had terrific relationships with outside constituencies. I think Andy is a thinker, an innovator also, and I think he tries to find solutions and implement them. I’ve been very, very pleased with Andy’s CEO status. The board was looking for somebody who could carry the PJM flag, and I think Andy does it exceptionally well.”
The More Things Change…
Prior to joining the board, Schneider knew little about the power industry, though he was highly experienced in Wall Street’s exchanges for commodities, securities, futures and other markets. He was the general counsel for the Commodity Futures Trading Commission from 1975 to 1977. That understanding of “pure” markets has informed his appreciation for the challenges of PJM’s administrative markets.
“We were just starting to put LMP into effect. … Capacity markets came on right around that time. It was all sort of new. I don’t really know what it was like before, but you can envision the utilities in effect having vertical dominance over the markets and operating in their own little spheres,” Schneider said. “It’s incredible because [RTO markets], they’re make-believe markets. Every time something goes wrong, there’s another bell that [gets added] on, another whistle that goes on. … There’s always a revision to an artificial market. … as something develops in a marketplace, they make the change that’s necessary to cure that particular thing, which then leads to another change, which leads to another change. So, they’re always evolving markets; they’re never rigid.”
The concept has been evolving since PJM opened its first bid-based energy market in 1997, and Schneider doesn’t expect that to change.
“When you have a [Market Monitor] and a senior staff as innovative as they are, I think you’re going to see change,” he said. “Frankly, I’d like — the stakeholders would like — to see less change so that it stabilizes. … But it’s just the way the world it is. It just changes.”
But some of the foundational pieces, like the capacity market, are likely to remain constant, Schneider insists.
“The sine qua non of PJM has been the capacity market,” he said. “It’s hard to think about … PJM without a capacity market, and it’s served a very useful purpose.”
Schneider remains particularly proud of PJM’s expansion during his tenure, both geographically — in reaching out to Commonwealth Edison’s territory in Chicago — and structurally in the size and variety of its markets. The desire for growth has meant challenges, though.
“There was a time when we were talking about merging New England ISO, NYISO and PJM, and that turned out to be a terribly divisive issue,” Schneider said. “I advocated for it because I thought it would solidify the same concept of expansion out to the west, to the north. … It divided the board a little bit at the time, and I don’t think our friends in New York or New England particularly copped to it, so it was something I think I regret in retrospect.”
Still, Schneider believes that PJM has room to grow.
“The only place you can go is basically to the south, and that’s always a possibility, but it’s nothing that PJM is actively seeking, nor should it. If the opportunity presents itself, it’s certainly a discussion item,” he said.
On market efficiency, he argued they’ve become “almost too successful, in that the prices are so low that resources are finding it hard to make sufficient money to be effective.”
Schneider said he is strongly opposed to anything that might suffocate the market, such as Energy Secretary Rick Perry’s efforts to subsidize coal and nuclear generators.
“I personally believe that this whole business with the Department of Energy and the threat that that creates for markets is an existential threat to PJM itself, it’s very existence, because if you foul up these markets — which is what I think the DOE proposal would do — then you’ve in effect taken away what is PJM’s great strength and characteristic, which is its ability to have functioning markets that have performed so well,” Schneider said. “It’s been an unbridled success, and I don’t want to see that go away.”
He said PJM’s current analysis into the grid’s resilience should determine which way to go.
“I think you have to look at resilience in a very holistic way, and you have to look at it some years down the road,” Schneider said. “Reliability is not a problem. Whether the fuel system is secure five years out, 10 years out, is a question that I think needs to be examined … and we’ll see where that leads. It may lead to something that says, ‘Things are fine; leave it alone’ — although you have a government that’s trying to push in a different direction — or one that says maybe we need to tweak this or tweak that and give a value to some resiliency characteristic that we hadn’t given a value to before.”
The resilience challenge differs from the Capacity Performance changes implemented after the 2014 polar vortex, Schneider argued.
“The point of CP was really to have a system in which outages were very limited to a real inability to perform because of something that was more like an act of god than just because it hadn’t been dealt with in a significant way. … It incentivized generator performance,” Schneider said. “Now you’re in another world of resilience that takes on different characteristics and may lead to something like a significant Capacity Performance-type fix, or it may not.”
He found it hard to identify the most difficult issue PJM faced during his tenure.
“Each problem that you tackle has a problem to it. When we put in Capacity Performance, for example, everybody was complaining, ‘You’re going too fast.’ And, on the other hand, if you didn’t go fast you’d miss the next year, and the thought of generators [having a] 20% outage [rate] or anything like the polar vortex was just [very bad] so we had to move,” Schneider said. “You’re not going to satisfy every constituency. Sometimes the way you know you’ve done something right, is everybody’s mad at you.”
Polar Vortex
Schneider insists he never worried the lights would go out during the 2014 scare.
“We came close to having to pull back and blackout, so it wasn’t fun. Everybody was worried about that, but we pulled through,” he said of the incident. “I’m never nervous. I have tremendous faith in the management team at PJM. I always have from the very first inception, and you could see they were very talented people who thought things through and came to reasoned conclusions, which I think is all you can ask of people.”
Board Stuff
Schneider hedged when asked whether his time on the board matched what he had envisioned, saying it worked out “a little of both” — unexpected and how he had planned. He said he spoke with Ott weekly to determine if anything needed to be reported to the board. “Over 21 years, as you can imagine, there are have been plenty of issues du jour,” he said.
He transitioned quickly to praise his colleagues on the board.
“I think it’s been a very responsible and responsive board, and I think that has contributed to PJM’s success in a great measure. We’ve been fortunate. There are diverse people who come on that board, and I can’t say there’s been a clunker among them. That’s a very pleasant thing,” Schneider said. “We were going to be a true corporate board. We weren’t going to be a stakeholder board or any of the other variants that are around in the ISO community. To me, that principle of being a true corporate board was essential to the success of PJM.”
Schneider emphasized PJM’s “very good relationships with most of the ISOs” and the board’s “deep sense of fiduciary responsibility” to states, the Market Monitor, stakeholders and consumers.
Even with very diverse backgrounds, board members come to consensus, he said. “It is a very, very rare time that we come away with a divided board,” he said.
Future Plans
Going forward, Schneider said he’ll only attend the monthly MRC meetings as a hired consultant advocating for a client. He has been a senior consultant at Charles River Associates since 2010 but “studiously avoided the energy field” because of potential conflicts of interest. Now that those conflicts no longer exist, he’s ready to step into the energy field.
“I loved it,” he said of his run. “It’s been a great experience with some really extraordinary people. I’ve been very pleased by it. … I sure as hell enjoyed it. It’s been great fun.”
NYISO is floating a proposal that would incorporate the cost of carbon into the ISO’s wholesale market by debiting each energy supplier a uniform carbon emissions charge as part of its settlement, eschewing an alternative approach that would levy region-specific charges for imports.
“The process we envision is very similar to how we handle invoicing today, where load-serving entities (LSEs) are debited the locational-based marginal price (LBMP), and now the LBMP will have a carbon price effect,” Michael DeSocio, the ISO’s senior manager for market design, told New York’s Integrating Public Policy Task Force (IPPTF) Monday.
The May 14 discussions were part of issue “Track 1” in the group’s five-track effort to price carbon emissions, which required development of the straw proposal.
The ISO’s proposal relies on a “status quo” carbon pricing approach (referred to as Option 1) that would not consider the specific carbon content in energy trades from out of state. A second option under consideration would’ve evaluated marginal emissions rates from out-of-state imports.
| Brattle Group
Both options appeared in a Brattle Group presentation to the task force last month, with Brattle favoring Option 2’s more aggressive approach to external transactions. But DeSocio said choosing the second option of “color-coding megawatts” outside New York would be too complicated. (See NY Carbon Task Force Discusses Seams, ‘Leakage’.)
DeSocio said the ISO is not aware of all supply positions outside the New York Control Area and whether there are offtake positions from one external generator to some external load. That means the energy from a source external to NYISO could be coming from a coal plant in Michigan, for example.
“I don’t have the tools to guarantee that what I’m getting is getting the right attributes assigned to it,” he said.
Rather than try to develop all those tools, which would cost time and money, the ISO is attempting to keep market participants on an even playing field to avoid making a trade into or out of New York harder, or create a bigger barrier to entry, DeSocio said.
Imports will add the charge to their offers, in effect competing with internal resources on a “status quo basis” with the same relative costs as if no carbon charges applied to anyone. Exports are similar but with a credit.
New York Imports and Exports | Brattle Group
“We think Option 1 does a nice job of keeping the carbon price self-contained and easy to manage,” said DeSocio. “We think it’s a reasonable approach that offers a lot of the same benefits without a lot of the complexity.”
Allocating Residuals
The straw proposal foresees LSEs being debited the LBMPs, “but then the LSEs would be credited all of the collections that we refer to as the carbon charge residuals from the suppliers that are emitting,” said DeSocio. “So, there’s a debit, and a credit, but at the end of the day on the invoice there’s only one charge, and that is the net of the two. That’s the concept.”
In allocating carbon charge residuals, the ISO chose to levelize the net impact so that customers across the state would end up paying the same rate, consistent with carbon affecting everyone and also with how other decarbonization policies are applied to rates, he said.
“There is an externality to the wholesale competitive market,” said DeSocio. “That externality has to do with environmental attributes, including the cost of carbon. There’s money being spent outside of the competitive market to try to deal with decarbonization. So, the goal of the carbon price would be to incorporate that externality to the maximum extent possible into the competitive market as directly as possible.”
Howard Fromer, director of market policy for PSEG Power New York, said that with the increasing number and scale of state solicitations for clean energy, offshore wind and energy storage, state agencies and regulators should make their contract language capable of accommodating a possible carbon charge.
“The numbers are mounting quickly, so if you don’t do something soon to avoid double-dipping, you’ll run into problems,” Fromer said.
Social Cost of Carbon
The straw proposal says the New York Public Service Commission (PSC) would set the gross social cost of carbon (SCC) in dollars per ton of CO2 emissions “pursuant to the appropriate regulatory process.” (See NY Looks at Social Cost of Carbon, Modeling.)
Representing a coalition of large industrial, commercial and institutional energy customers called the Multiple Intervenors, Couch White attorney Michael Mager said, “If carbon pricing were to be implemented under the straw proposal, one of Multiple Intervenors’ concerns would be how the social cost of carbon (SCC) gets set and updated.”
Mager said his clients could not accept the SCC being subject “to update and modification at any time by the PSC in its discretion.”
“It’s one thing if there’s something that’s set by schedule or set by certain parameters, like the annual demand curve update where it’s a formula, everyone knows it, it’s set in advance, and it gets changed in a non-controversial manner,” Mager said.
“This is a little bit of public policy and a little bit of wholesale market, which is territory that we haven’t dealt with too often,” said DeSocio.
DeSocio suggested the ISO’s public policy transmission process could offer guidance on how to proceed.
“It will be helpful to have more of an understanding of what any process would look like for setting [SCC], especially if we were to consider moving forward with including the cost of carbon in the wholesale market,” said DeSocio.
David Clarke, director of wholesale market policy for Power Supply Long Island, asked what would happen if FERC or the federal government decides a lower cost of carbon is appropriate and asserts authority over the rate used under the Tariff.
“We’re kicking around a sixty some-odd dollar per ton number, but what if FERC comes back and says the number’s twenty bucks, or FERC comes back and says the number is three dollars?” said Clarke.
“Certainly, if FERC [were] to develop some policy regarding how to value the cost of carbon in a wholesale market, we would need to take a step back and think about that,” DeSocio said. “At the moment, we’re unaware of any such policy.”
He added that in using a state-supported SCC, the ISO wants to make sure its “incorporation is stable and provides robust market signals” for investment decisions.
The task force had its own charter on the agenda Monday but deferred serious discussion of it until the stage of discussing next steps — around July 9, when the path forward should be clearer. The overall study results are scheduled to be presented in September.
The task force next meets May 21 at NYISO headquarters to address issue “Track 5” assumptions and scenarios on customer impacts, including wholesale customers.
KANSAS CITY, Mo. — As chairman of SPP’s Holistic Integrated Tariff Team (HITT), Tom Kent has been asked to lead a team responsible for addressing “the many issues challenging” the region.
Simple things, like cost allocation and transmission zones, Z2 credits, the planning and study process, and what to do with 60 GW of wind in the planning queue — issues that have vexed staff and members for the past several years.
“There are some pretty meaty topics,” admitted Kent, Nebraska Public Power District’s COO.
The 17-person team includes state regulators, SPP directors and key member representatives, all of whom also have day jobs. So how do you keep everyone on track?
“We have to come together on how we want to eat the elephant, so to speak, right?” Kent said before the team’s April kickoff. “It’s a pretty big topic, and you’ve got to take it one bite at a time. We’re going to spend a lot of our time kind of understanding what the elephant is, and what the scope is, and how big the elephant is. Hopefully, we’ll get to the point where we’re able to start prioritizing which bites we want to take off and go after.”
Fortunately, Kent has plenty of experience in meeting management and team dynamics.
“It’s nothing new. It’s a broader group with different perspectives, but the dynamics of leading a team or a group are very similar,” he said. “You’ve got to get everyone to start working together and understand how we’re going to function as a group. Keep the group focused on the priorities that we’re working on — and there are going to be lots of things to work on.
“It’s just typical team dynamics, right?”
HITT Squad
The “HITT squad,” as it is called informally, encountered some early turbulence when several stakeholders complained about the secrecy under which it was created in March. SPP’s Board of Directors approved the team’s formation during a closed-door meeting. (See SPP Questioned on Secrecy over Tariff Team.)
SPP proposed that most HITT meetings be held face to face, with stakeholders “encourage[d]” to participate by dialing in, unless they are presenting to the team in person. Early discussion about the group suggested that only team members would be allowed to participate in meetings, but other stakeholders are now invited to provide information and ask questions.
“I wouldn’t use the word ‘secret.’ It’s just new,” Kent said. “You’ve got to give everyone an understanding of how the group’s going to work, what the scope’s going to be, what the priorities are going to be. You can’t take the elephant all at once. I expect for a while, at least, the meetings will be focused on the team.”
The early focus has been on education and technical presentations. The HITT’s first meeting was spread out over two days following the April board meeting, with staff delivering detailed presentations on SPP transmission, planning and cost allocation, and markets and operations.
The team began drawing up a list of hot topics and requested feedback from stakeholders on the issues, topics and/or challenges they believe it should be addressing.
Afterward, Kent shared with the HITT a study on the market value of variable renewables and additional background materials.
“I thought we covered a lot of good information,” Kent said.
The team next meets in Dallas on May 16. On the agenda: developing a problem statement, reviewing requested information, and more technical presentations and education.
The HITT has been tasked with filing a written report by April 2019, but it can request additional time, if needed. It will report to the board’s Members Committee and provide status reports to the Regional State Committee, Markets and Operations Policy Committee and Strategic Planning Committee.
The team includes Directors Larry Altenbaumer and Graham Edwards, state commissioners Shari Feist Albrecht (Kansas Corporation Commission) and Dennis Grennan (Nebraska Power Review Board), and member representatives for the investor-owned utilities, cooperatives, independent power producers, municipalities, state agencies and independent transmission companies.
Cindy Ireland, the Arkansas Public Service Commission’s director of research and policy, has joined the team as a liaison for the Cost Allocation Working Group (CAWG). The RSC had requested a liaison, as much of the HITT’s work will touch on that of the CAWG’s.
“We don’t want to retrace ground other groups are working on,” Kent said. “That coordination and working together is going to be important for the CAWG, and it’s also going to be important for other groups, potentially.”
Taking on the Animal
The HITT has been asked to assess:
Transmission planning and study processes: generation interconnections; the interconnection queue; aggregate studies; energy resource interconnection service and network resource interconnection service; capacity requirements, including more attributes than energy; and related FERC planning requirements.
Transmission cost allocation issues: highway/byway; directly assigned costs; Attachment Z2 credits; cost allocation impacts on transmission pricing zones with large wind resources; and state-by-state supply resource mix requirements and/or goals.
Integrated Marketplace: effects related to a changing resource mix; access to lower cost generation; potential changes in production tax credits; using market-based compensation for varying attributes of different types of generators.
Disconnects or potential synergies between transmission planning and real-time reliability and economic operations.
Additional areas and/or issues as appropriate and reasonably related to its scope of work.
The team has been modeled after the Synergistic Planning Project Team (SPPT), which was formed in 2008 to suggest a process addressing deficiencies in SPP’s then-existing planning processes. In just a matter of months, it filed a report that led to the RTO’s Integrated Transmission Planning process and the highway/byway cost allocation methodology.
SPP is hopeful the HITT will be just as successful.
General Counsel Paul Suskie, who represented the Arkansas PSC on the SPPT and is the staff secretary to the HITT, said the SPPT’s work led to FERC Order 1000.
“Three of the five commissioners told me that SPP’s approach to planning is what the nation needed,” Suskie said.
Suskie also recalled conversations he had with fellow team member Barry Smitherman, then chair of Texas’ Public Utility Commission. Texas was in the midst of its Competitive Renewable Energy Zone project, which used state money to finance nearly $7 billion in transmission infrastructure to connect West Texas wind energy with cities to the east. Customers would eventually pick up the tab through CREZ fees on their bills.
The two would tease each other over the best methods to fund transmission buildouts.
“I’d always call [regional funding] socialization,” Suskie said. “Barry would tell me, ‘In ERCOT and Texas, they call it uplift.’”
Suskie is just one of three holdovers from the eight-person SPPT, which also included Dogwood Energy’s Rob Janssen, the HITT’s vice chair, and SPP COO Carl Monroe.
“That experience and that background, having gone through the process before, will be invaluable,” Kent said. “I’m excited about being able to sit down with them and take on this animal, and talk about some different issues and look for opportunities to improve things going forward.”
WASHINGTON — FERC Chairman Kevin McIntyre, the luncheon speaker on the second day of the Energy Bar Association annual meeting last week, said he’s often asked about his priorities as head of the commission. “I love this [question] because it suggests I get to pick,” he said to laughter.
“We get to select some of the topics we work on but … I arrived in December and at that time, there was a faint ticking sound … on the 11th floor of the FERC — something awaiting prompt attention,” he continued. The ticking sound was the Dec. 11 deadline for responding to Energy Secretary Rick Perry’s Notice of Proposed Rulemaking to provide price supports for coal and nuclear generation.
“And I thought, in the [tradition of the] Hippocratic Oath: First do no harm. So, my first official and brave act as FERC chairman on Dec. 7 was to humbly request more time,” McIntyre said. “I’m happy to say that such time was granted and that we beat our extended deadline by a couple of days. And we managed a five-to-nothing order taking action on the Notice of Proposed Rulemaking that was proffered to us by the secretary, deciding as a commission that we could not adopt it in the form it was presented to us.” The commission instead opened a new docket on resilience — a proceeding that prompted more than 100 comments last week. (See related story, Don’t Rush on Resilience, Commenters Urge.)
McIntyre also discussed the commission’s challenges in determining whether state subsidies for generators based on their fuel source is unduly discriminatory. “Isn’t that an unfair market advantage? These are valid questions, not crazy questions. And we have before us the work of trying to figure out answers to them, and every bit as difficult as that, trying to figure out how to implement sensible policy steps based on those answers. This plays out in a number of different ways, and I wish I had all the answers. … As lawyers we like challenges … and boy is this one. It’s a real toughie.”
Former FERC General Counsel Max Minzner said the “defensive regimes” that have shielded energy companies from antitrust liability — the state action doctrine, federal pre-emption and filed rate doctrine — are being eroded.
One source of the erosion is litigation, he said, referencing the Supreme Court’s 2015 ONEOKdecision, which found that federal pre-emption under the Natural Gas Act does not prevent state antitrust suits over pipelines’ price manipulation.
Minzner, now a partner with Jenner & Block, also cited technology that can overcome natural monopolies and regulatory changes such as the development of federally regulated gas and power markets. “And finally, one of the areas that I find most fascinating, is erosion from legislative change. The rise of the market manipulation authority within the Energy Policy Act of 2005 has an overlay on the filed rate doctrine.”
Minzner was the moderator of a panel on antitrust trends, where panelist R. Scott Mahoney, general counsel and chief compliance officer for Avangrid, sparked a discussion on the risks of making intemperate statements in emails, text messages and internal presentations that can be obtained in discovery.
Mahoney said he urges Avangrid employees “to think about doing that in a … more precise way so that you don’t create the one email that then gets waved around” as evidence of anticompetitive behavior.
Richard M. Lorenzo, chair of Loeb & Loeb’s antitrust practice, recalled the damage done to Microsoft’s antitrust defense in 1999 after testimony that company Vice President Paul Maritz had threatened to cut off rival Netscape’s “air supply.”
He cited a 1982 phone call from American Airlines President Bob Crandall to Braniff Airways President Howard Putnam — which Putnam recorded — in which Crandall said, “Raise your goddamn fares 20%. I’ll raise mine the next morning.”
“So, what you write in memos matters. [We’re] trying to emphasize to employees at all levels of the company — especially at the management level — to tone it down. Write factually as opposed to emotionally with lots and lots of adjectives. It’s very important because this stuff comes back to bite you when there is discovery.”
“People want to make a splash. People want to be remembered, and so therefore they’re always pushing the envelope with respect to PowerPoints and other ideas [using] colorful language,” added Michael O’Connor, chief legal executive for law and human resources for the Salt River Project. “And once you have one of these cases and you put it in that light and it’s thrown up in a federal district court or all over the papers, people remember that.
WASHINGTON — The Energy Bar Association closed its annual meeting last week with a panel discussion with five former FERC chairs whose terms collectively spanned two decades. The former chairs offered entertaining anecdotes about the past while expressing pride over the growth of competitive markets — and frustration over forces they said threaten them.
James Hoecker (1997-2001) jokingly referred to his tenure as the “Cretaceous period of FERC regulation,” a time when he said there was less state-federal conflict but also no FERC authority to impose meaningful penalties on market manipulators. He started at FERC as a staff attorney in 1979 and left for a time before returning in 1993 as a commissioner. He cited Order 637, which revised gas pipeline rules to encourage competition, and Order 2000, which set the requirements for RTOs, among the biggest accomplishments of his tenure.
“FERC had not gotten to be so visible in the media because of its work in energy infrastructure as it’s become recently,” said Hoecker, now counsel to the trade group WIRES. “I guess I’m thankful for that.”
Pat Wood III (2001-2005) expressed regrets over not returning a phone call to Southern Co. CEO H. Allen Franklin in 2002 after announcing Standard Market Design, “which was going to solve all the problems that happened in California” during the 2000-2001 Western energy crisis.
“Maybe I’m overselling my persuasive skills and it was never meant to be, but [I wish] I could have talked them out of being so intransigent against Standard Market Design,” said Wood, now chairman of Dynegy.
He also wished he had been “more willing to accept imperfections” in the RTO applications filed by Southern and other companies in the Southeast and West.
“Accepting that could have avoided what I call the carnage that’s happened [in the Southeast] with noncompetitive generation. … But I was pretty rigid on making sure they met the criteria of Order 2000 and neither of those [regions] had” sufficient independence.
Joseph T. Kelliher (2005-2009) said his pre-commission career as a congressional aide helped him in negotiations to eliminate “hostile” anti-FERC provisions from the Energy Policy Act of 2005 shortly after becoming chair. The law gave the commission the authority to issue enhanced penalties for market manipulation and mandatory reliability rules, and deputize NERC as the Electric Reliability Organization.
“At the time, I had a lot of doubts about NERC’s capacity to discharge their responsibilities under the act,” said Kelliher, now NextEra Energy’s executive vice president for federal regulatory affairs. “And I thought it was necessary for FERC to adopt a larger role until NERC expanded its capacity, almost like a big brother throws his arm around his little brother until he gets some more muscle. … I think NERC is a much more capable institution than it was in 2005.”
Jon Wellinghoff (2009-2013) said his background as Nevada’s first consumer advocate informed his chairmanship, during which he “tried to ensure that the markets were open and fair” for technologies such as renewables and demand response.
Wellinghoff expressed special pride in Order 745, which required that RTOs pay DR resources LMPs, and Order 755, which required RTOs to compensate fast-regulation resources for speed and accuracy. He also cited Order 719, requiring RTOs to treat DR offers like generation, and Order 764, which aided the integration of variable energy resources.
“I think they’re all important to ensuring that all resources can efficiently and effectively compete in these markets. And then … in Order 1000, the transmission planning order, we tried to ensure that there was some level of competition in the planning and selection of transmission.”
Wellinghoff, who has continued to advocate for distributed energy resources as CEO of consulting firm GridPolicy, added he is “very encouraged” by actions the current commission has taken to open markets to energy storage and DERs.
“You’re seeing the distributed resource technologies just explode. You’re seeing the enabling technologies underneath them — which are really the communication and control technologies — get less and less expensive … and more available to consumers. My son is truly a computer geek. … He was cataloging our house the other day: We have 52 addressable devices in the house.”
Wellinghoff said he’d like to see more done to open competition in transmission. Without competition, he said, the industry is “going to stamp down innovation. There are many innovative technologies coming into the transmission space … that are substitutes for transmission that need to have the opportunity to compete … against the incumbents.”
Norman Bay (2015-2017) talked of the obligation he felt to live up to the legacy of his predecessors. “As I listened to their comments today, I’m struck by … the nonpartisan nature of the work that we’ve been doing. The ability of Republicans and Democrats alike to come together to get things done to further the public interest,” said Bay, now head of Willkie Farr & Gallagher’s energy regulatory and enforcement group in D.C. “I would bet that if anyone were to listen to the comments of anyone on this stage and didn’t know what political party they belonged to, they would have no idea if that person was a Republican or a Democrat. And how great is that?”
‘Crony Capitalism’
Wood and Bay debated the impact of zero-emission credits — enacted in Illinois and New York and under consideration in New Jersey — to subsidize nuclear generation.
“Are they a good idea? No. They’re crony capitalism by just a new name,” Wood said. “I do think that FERC has got to take … an informational role to let these state legislatures know … what damage these kinds of things do the operation of the competitive markets that we worked for a quarter century to set up. That’s exactly what they are. The resilience thing looks like a continuation of the same crony game,” referring to calls for subsidies for coal and nuclear plants with onsite fuel. “I just think it’s poisonous to markets.”
Bay, however, said ZECs are states’ response to the markets’ failure to price carbon emissions. “I think everyone on this panel would agree that the first best solution if you care about carbon emissions is to put a price on carbon and then harness the power of markets. That clearly has not happened.
“The second-best solution — and I would say second by a long ways — is to provide financial incentives to resources that do not produce the negative externality. And that’s essentially what states are trying to do. Running the market now without taking into account the negative externality results in an inefficient market outcome.”
“And that would be fine, I think, if all zero-emitting resources now and in the future could qualify for that,” Wood responded. “As opposed to the New York case, which is very egregious, that named plants [eligible for ZECs] and one [Indian Point] was excluded.”
Future of Capacity Markets
Wood and Wellinghoff responded to a question about the future of capacity markets.
“As one who comes from the energy-only market of Texas, it works,” said Wood, acknowledging that the market will be stressed this summer because of the reduction in ERCOT’s reserve margin. “It will be a real big test. So, ask me this question at the end of September.” (See ERCOT Gains Additional Capacity to Meet Summer Demand.)
Wellinghoff said he has grown increasingly skeptical of capacity markets.
“Don’t tell him this, but Bill Hogan may be right,” said Wellinghoff, referring to the Harvard University professor, a prominent proponent of energy-only markets. “Ultimately, I think capacity markets are very difficult to design correctly and functionally. I’m currently working in Alberta. The ISO and the government there have committed to put a capacity market in with a balancing energy-only market. I’m working with a client there trying to help them to help the ISO come up with a design that will work for everybody. And we’re close to pulling our hair out!”
Confessions
At the end of the session, moderator and FERC Administrative Law Judge Lawrence Brenner elicited confessions from some of the panelists over “impulsive” actions they took as chair.
Bay recalled being up until 2 a.m. the night before the FERC Christmas party because he insisted on hand squeezing the 20 pounds of limes needed to make proper margaritas. “You can probably divide the world into two camps: the people who believe that a margarita can be made from a mix, and the people who realize, no, you really need to use fresh squeezed lime juice,” he said.
Kelliher recalled when vineyards near California’s Russian River petitioned him to authorize the release of water from hydro projects during a drought.
“Of course my first thought was, ‘I really like Russian River red wine.’ But my question to the staff was, ‘What legal authority do I have to do that?’ And the response was, ‘Highly questionable’ — FERC-staff speak for nonexistent.
“And I thought about it for about 10 seconds and I said, ‘Release the water!’” he said to laughter. “It felt very Christ-like. I knew it was the closest I would get to being holy. … I wasn’t turning water into wine but authorizing water. … And I thought if I go down [get overturned], I’ll get a Wine Spectator cover or something.”
SPP’s winter real-time prices increased 4.6% from the previous year, according to the Market Monitoring Unit’s latest quarterly State of the Market report.
The report said real-time prices averaged $25.69/MWh, compared with $24.57 the previous winter, when prices jumped 37.9%. Day-ahead prices this winter averaged $24.07/MWh, 7 cents shy of the 2017 average.
SPP’s Low Winter Prices | SPP MMU
The MMU reviewed the report, which covered December 2017 to February 2018, with market participants during a webinar Friday.
Also last week, the MMU released its annual State of the Market report, saying SPP’s market showed increasing flexibility and improving efficiency during 2017. The MMU had shared a draft with the RTO’s Board of Directors in April. (See “MMU Shares Draft of State of the Market Report,” SPP Board of Directors/Members Committee Briefs: April 24, 2018.)
The quarterly report noted average gas and electricity prices — which have historically been highly correlated — diverged slightly this year, with gas dropping from $3.08/MMBtu in 2017 to $2.64/MMBtu in 2018. Panhandle Eastern hub prices ranged from $2.50 to $2.80/MMBtu from February 2017 until January, when they spiked to $3.23/MMBtu during a cold snap.
SPP set three new winter peaks Jan. 16-17, topping out at nearly 43 GW. Oil-fired units set prices during the period that “routinely exceeded” $400/MWh in western Arkansas, eastern Texas and southern Missouri.
Winter Prices by LSE | SPP MMU
SPP and MISO were forced to use market-to-market redispatch Jan. 16-18, resulting in SPP collecting $2.66 million during that time. The Neosho-Riverton flowgate was responsible for most of the costs, as it has been since the two RTOs began the M2M process in March 2015. Congestion on the flowgate has resulted in $26.5 million in payments to SPP, more than half of the $51.4 million M2M charges MISO has incurred.
The MMU said the flowgate also caused Empire District Electric and the Missouri cities of Carthage and Springfield to see the highest winter prices in SPP’s footprint, with Carthage seeing average real-time prices of slightly more than $50/MWh.
Other highlights from the report include:
An increase in the occurrence of negative price intervals, with winter 2018 levels higher than previous years.
A nearly 7% increase in the hourly average load for winter 2018 from winter 2017. December 2017 was at a similar level to the prior year, but January and February 2018 average loads were nearly 11% higher, driven primarily by lower-than-normal temperatures.
A 7% increase in average monthly real-time generation from winter 2017 to winter 2018. Coal-fired generation its downward trend, accounting for only 46% of energy produced during the winter. Wind resources accounted for 26% of total generation.
A 36% day-ahead wind capacity factor, which increased to 46% in the real-time market. The disparity between day-ahead and real-time capacity factors contributed to the increase in negative price intervals.
CAISO is taking comment on the latest revisions to its ongoing policy initiative to better facilitate the participation of energy storage and distributed energy resources (ESDER) in its markets.
ESDER 3 is organized under the broad themes of demand response; “multiple-use applications” that allow storage to provide services and receive revenue from more than one entity at a time; and non-generator resources (NGRs).
The latest document updates the previous iteration that was published on Feb. 15, using feedback from stakeholders and a late March workshop that tackled highly technical problems related to integration of the resources. (See CAISO Storage, DER Plans Progressing.)
Major changes include a reorganization of each proposal into three categories:
“Pre-market,” which describes changes needed before a resource can participate in the CAISO market;
“Market,” which identifies potential modeling and bidding rule changes to allow participation; and
“Post-market,” which examines implications for settlement, including measures of performance such as customer load baselines.
PDR Bid Changes Afoot
Among the new updates for DR is a proposal to allow proxy demand resources (PDRs) — one or more DR resources allowed to bid as a single resource — to bid on hourly and 15-minute bases, with an ability to change the bid within an hour. The proposal would redefine issues around infeasible real-time dispatches of demand response to conform with separate changes CAISO is making to its day-ahead market. (See CAISO Says Changes Will Better Match Forecasting, Demand.)
“Stakeholders such as the Joint DR Parties are in support of the proposal but do not believe the expanded bid options fully resolve the issue of infeasible dispatches,” CAISO said in the revised straw proposal. The Joint DR parties include CPower Energy Markets, EnerNOC and Energy Hub.
Also proposed in ESDER 3 is the removal of a requirement that DR be aggregated under a single load-serving entity, which CAISO said is supported by a majority of stakeholders. The ISO said changes being proposed in the day-ahead market proposal — including combining the integrated forward market and residual unit commitment processes while introducing an integrated resource plan procurement — eliminate concerns that had been raised about some default energy bids being rejected.
CAISO is also looking at the design of the proxy demand resource-load shifting resource (PDR-LSP), which is a DR resource that provides load curtailment and also gets paid for dispatchable load consumption to shift load. The ISO said such resources will register as two separate resources with load consumption compensated via the “metered energy consumption” methodology.
DER company Olivine recommended the creation of a more refined load-shifting product, not just a consumption product, but CAISO said the separation of the resources does not create a “consumption-only” product. A requirement that PDR-LSPs have directly metered energy storage will guarantee that the energy being discharged and charged will result in a load shift, the ISO said.
Electric Vehicle Supply Equipment Examined
As another component of ESDER 3, CAISO is working to recognize the load curtailment capability of electric vehicle supply equipment (EVSE), which is seen as a way to absorb excess output from renewables. Currently, a DR resource that includes EVSE is measured without considering the equipment’s effect on load dynamics, and the ISO is working to meter the data to measure the performance of EV infrastructure. The ISO has established a distinction between EVSE located in residential versus nonresidential areas.
EVSE can already participate in markets using the “metered generation output” (MGO) performance measurement (approved by FERC as part of ESDER 1), which recognizes a sub-metered storage device’s contribution to a facility’s overall load curtailment during a CAISO dispatch event. But the ISO cannot currently accommodate a sub-metered resource with a different performance profile than its host facility load. The ISO proposes to enable EVSE sub-metering and extend the MGO performance method for EVSE independent of, or in combination with, its host customer.
CAISO’s proposal to sub-meter electric vehicle supply equipment (EVSE) | CAISO
“Sub-metering resolves the lack of 15-minute interval metering at the host facility for measurement of curtailment in five-minute intervals, enables direct measurement of the actual EV load curtailment achieved and creates a more tailored market participation model for EVSEs,” CAISO said.
Under the initiative to facilitate market participation for NGRs, CAISO dropped a proposal to identify commitment costs for NGRs in its separate Commitment Cost and Default Energy Bid Enhancements proposal, leaving those resources to be modeled as not having start-up, minimum load and transition costs.
CAISO is taking comment through May 21 on the ESDER 3 proposal and said it will continue to hold working groups, including focused working groups to examine more complex issues or those that have cross-jurisdictional concerns. Other participants in ESDER 3 are EV charging station company eMotorWerks and the California Energy Storage Alliance.
The California Public Utilities Commission on Thursday voted unanimously to allow Southern California Gas to temporarily increase gas injections into Aliso Canyon, but it denied a request to increase the storage facility’s allowable capacity.
The commission said it approved the decision “recognizing the urgent nature of ensuring reliable gas delivery during peak summer periods and with the summer season quickly approaching, as well as various pipeline outages and curtailments constraining gas flows into the SoCalGas system.”
There is a movement among residents of the nearby Porter Ranch neighborhood in Los Angeles to shut down Aliso Canyon, with many complaining of health impacts even after the massive gas leak at the facility was contained in February 2016, after being discovered the previous October.
While the CPUC’s current protocol is to allow for withdrawals only as a last resort when needed for reliability and other alternatives are exhausted, the facility is proving to be critical to electricity reliability in the region. Its potential loss has been a topic of increasing concern for the commission. When questioning CPUC President Michael Picker during a March hearing after the commission authorized gas withdrawals, State Sen. Henry Stern expressed alarm that it had “secretly granted” SoCalGas’ request to increase usage of the facility. (See Picker Seeks Guidance on IOUs, Aliso Canyon.) But Picker said the commission’s hand is being forced because of gas supply concerns.
‘Even More Urgent’
The CPUC said its measure Thursday will improve system reliability this summer and next winter. It approved several measures within SoCalGas’ second injection enhancement plan, which the company said is needed to meet customer demand and prepare the facility for winter. The plan allows the company to implement temporary modifications to its operations to increase injections and temporarily increase storage injection capacity.
But the commission denied a request to increase the allowable inventory at the facility to enable more systemwide injections and denied a request for more flexible use of the facility through a temporary deviation from certain rules.
Location of the Aliso Canyon gas storage facility
Aliso Canyon is the largest of the company’s storage facilities and had a capacity of 86.2 Bcf before the leak. Injections into the facility were forbidden through a proclamation of Gov. Jerry Brown in May 2016 until a safety review could be conducted. The state Division of Oil, Gas and Geothermal Resources last July certified a SoCalGas safety plan, allowing injections to resume and the facility to operate at pressure of up to 2,926 pounds/square inch, which translates into a gas inventory of 68.6 Bcf, or about 80% of its capacity.
The CPUC approved a similar resolution for SoCalGas’ first proposed injection plan in June 2017 to support summer reliability last year. That decision also approved an agreement between CAISO and SoCalGas for summer reliability services through Sept. 30, 2017.
The commission said several pipeline disruptions have occurred since then. On Oct. 1, the day after the ISO’s reliability agreement expired, there was a rupture on SoCalGas Line 235-2, which is still not in service. Line 4000 also went under maintenance and is now operating at significantly reduced capacity. A right of way through the land of the Morongo Band of Mission Indians also expired, reducing the capacity of Line 2000. (See SoCalGas Pipeline Losses Spur Curtailment Warnings.)
“All of these outages have placed additional stress on the system, making storage injection even more urgent than it was in spring 2017,” the commission said.
In July, the CAISO Board of Governors approved a package of market rule changes specifically developed to deal with the reduced output of Aliso Canyon. The rules allow the grid operator to constrain the operations of gas-fired plants across the state and the Western Energy Imbalance Market in the face of tight gas supplies. (See CAISO Board Approves Aliso Canyon Rules Package.)
SoCalGas wrote to the CPUC on March 2 asking for the permission to immediately begin using Aliso Canyon to manage gas inventory and preserve withdrawal capability at other storage fields. The company was predicting colder weather and said that storage at other fields was critically low. “Noncore” gas customers such as gas plants saw curtailments, and lower storage levels made it more difficult to withdraw gas.
The commission authorized withdrawals on March 3, provided that SoCalGas coordinate with CAISO and the Los Angeles Department of Water and Power to reduce overall gas demand, and the withdrawals were only authorized through March 13. SoCalGas was to increase inventories at all facilities once demand hit normal levels. The commission directed SoCalGas to file the injection plan with the goal of rapidly achieving more storage capability at fields other than Aliso Canyon and to establish minimum month-end storage targets for the rest of 2018.
Still a Key Asset
The CPUC said that because of pipeline outages, capacity reductions and other limitations, SoCalGas’ technical assessment showed that under a worst-case scenario, there is not enough capacity for this summer to meet both customer demand and to inject additional gas into storage at the rates necessary to meet the winter season storage withdrawal rates as directed by the CPUC, even with the use of Aliso Canyon. Without the facility, the SoCalGas system would not be able to meet summer peak day demand, the commission said.
Under the plan approved by the commission Thursday, SoCalGas cannot guarantee gas storage inventory targets can be reached, even with Aliso Canyon available. The company requested that the allowable inventory at Aliso Canyon be increased to 30 Bcf from the current 24.6-Bcf limit. The commission said that request required additional examination and technical assessment.
SoCalGas estimates that it will reach the current allowable inventory next month and said not having additional injection capacity available will reduce the amount of gas available to the system on any given day.
In assessing Aliso Canyon, the CPUC is faced with the challenge of maintaining reliability while dealing with public opposition to a facility that has become a symbol of the hazards of dependence on natural gas. As unpopular as it is, the facility at present appears to be indispensable for keeping the lights on in Southern California.
