SAN DIEGO — The digital economy is driving construction of a massive amount of data and storage infrastructure that has many implications for the electricity grid, industry participants and regulators said last week.
Data centers are seen by states as bringing economic development, but they also create electricity and water demand that requires attention from regulators. Utilities and municipalities are designing tariffs specifically for data centers, which require significant infrastructure development within a certain utility footprint, Illinois Commerce Commissioner John Rosales said at a July 17 panel of the National Association of Regulatory Utility Commissioners’ Summer Policy Summit.
Rosales and others noted that the demand for data and storage infrastructure will only grow. “We are not putting down our smartphones or tablets anytime soon,” he said.
Commonwealth Edison Vice President Sheila Owens said that Northern Illinois houses 70 data centers with aggregate demand of more 200 MW, the largest 15 of which have annual demand growth of about 20% a year. She noted a dramatic statistic: 90% of the data ever created were generated in the past two years.
Data center
“Data centers are the manufacturers of the 21st century in our digital economy,” Owens said. She added that Chicago’s transportation access and colder climate benefit data center efficiency by reducing cooling costs.
Data centers have a high incentive to use energy and water efficiently, and many companies have sustainability offices that research siting concerns for them, Owens said. Legislation in Illinois has created incentives for using solar credits to commercial facilities. Data center operators tend to be interested in clean energy.
Former Florida Public Service Commissioner Eduardo Balbis said the number of data centers will increase in the U.S. as new technology, such as autonomous vehicles, is developed. He urged that state regulators partner with data center operators on energy-usage programs in order to attract the facilities.
States are now waiving taxes to account for data centers or adjusting rates, and regulators should give utilities flexibility to partner with data center operators, said Balbis, now managing director of Accenture Strategy.
DENVER — Before introducing a panel of Mountain West Transmission Group representatives during SPP’s recent Markets and Operations Policy Committee meeting, COO Carl Monroe assured everyone that they were sitting inside the cavernous Colorado Convention Center by pure happenstance.
“We set up this meeting in Denver two years ago,” before entering discussions with the group about SPP membership, Monroe said. “So, there is nothing nefarious by us having our meeting here.”
Not surprisingly, after Mountain West announced earlier this year that it intended to join an RTO, and preferably SPP, the MOPC meeting drew record attendance. SPP reported a head count of 185, with 173 attendees signing in. A good number of those were Mountain Westers — as those representing the organization’s various entities refer to themselves — and interested regulators from Colorado and other Western states.
Mary Ann Zehr, senior manager of transmission contracts, rates and policy for Tri-State Generation and Transmission Association, said Mountain Westers “showed up in force … to glean awareness of the SPP ‘process,’ stakeholder interactions and decision-making ability.”
They got a good dose of that, taking in a passionate, member-led discussion of cost shifts within the RTO’s transmission zones — an issue sure to be key should SPP integrate its new members. (See Divide Evident Between SPP Tx Owners, Users.)
“Members have been monitoring the zonal-placement discussion occurring in SPP for a few months now,” Zehr said. “Initial zonal construct and methodologies to address future zonal placement are critical decisional items.”
“We’re highly concerned about a lot of issues related to zonal placement,” said Joe Taylor of Xcel Energy, which owns Public Service Company of Colorado. “We don’t necessarily want to put ourselves at risk. We’re just not 100% resolved around how many zones there will be. Cost-shift negotiations among members … we’re not done with that.”
The Case for Membership
For his part, Monroe said he was pleased to have the Mountain West representatives present, saying they saw a demonstration of how SPP maintains its independence through membership diversity.
“They were able to witness firsthand the active engagement and meaningful voice our stakeholders have in the development of SPP’s policies, even during discussion of contentious issues,” Monroe said.
“My sense is that the group was pleased with the dialogue, ability to contribute and outcomes,” Zehr said. “It was also very helpful for members to be able to meet and have side discussions with existing SPP members.”
In return, Zehr and other Mountain Westers participated in a panel discussion, sharing background on each of their companies and explaining why the organization has decided to join an RTO.
Mountain West — comprising eight investor-owned utilities, municipalities, federal power marketing administrations and cooperatives, and their subsidiaries — announced in January that it was beginning discussions with SPP about joining. The group expects to arrive at a decision by October and could present a recommendation to the RTO’s Board of Directors in January 2018. (See Mountain West to Explore Joining SPP.
Mountain West members serve 6.4 million customers in and around the Rocky Mountains, with a coincident peak of more than 12 GW. Should the organization join, the new RTO’s Tariff would include all the DC ties between the Eastern and Western Interconnections, except for one in Canada.
“Our goal is to keep costs as low as we can for our customers by exploring any option,” said Platte River Power Authority’s Andy Butcher. “What does it cost versus the benefits? We believe there’s value, so that’s why we’re sitting at the table.”
A 2016 Brattle Group study found Mountain West could save $53 million to $71 million annually through 2024 by participating in a day-ahead market and replacing its nine tariffs with one. Eliminating pancaked rates for wholesale transactions and other tariff-revision concepts started the group’s dialogue about RTO membership.
Members said they also want to take advantage of modern market designs to maximize transmission capacity and use the most cost-effective generation. SPP’s Integrated Marketplace, with its day-ahead and real-time markets, is a huge selling point.
“Out here in the West, we use what we call available transmission capability,” Taylor told the MOPC. Noting that SPP’s transmission system is flowgate-based and Mountain West’s is flow-based, he said, “The [flow-based] contract methodology is very conservative. I think we’ll see great benefits without building additional transmission.”
Taylor also made a point of mentioning that, after the panel discussion, the Mountain Westers would be conducting their 70th meeting on Tariff revisions and RTO membership. They and SPP have formed a steering committee and working groups focused on governance, rate design, cost allocation, transmission planning, reliability coordination and the RTO’s Regional State Committee (composed of regulators from 10 different SPP states).
Monroe said SPP is following the same process it did when adding the Integrated System in 2015 and Nebraska utilities in 2009. The two sides are in confidential negotiations, with SPP staff keeping the board, RSC and Strategic Planning Committee updated during executive sessions.
“Most of the time is spent in educating both [parties], because there’s a lot to joining SPP, but we’re also trying to understand the parties that want to join, their concerns and how to address them,” Monroe said.
Asked whether Mountain West would be fully integrated with SPP’s Eastern Interconnection or on its own, Monroe said, “From an SPP staff perspective, we believe that having it all integrated together is the most beneficial form. SPP has technology it’s been exploring … and we believe it’s capable of running the market over the full footprint.”
In the end, each Mountain West utility will have to make a business decision.
“We’re doing that as individual companies,” Zehr said. “We have cost shifts associated with de-pancaking of transmission rates, we have implementation costs … lots of factors that drive our benefit costs as individuals.”
Other utilities from the region could also make the same business decisions about becoming RTO members, although they haven’t come out publicly.
“Because of some of the issues they’re still resolving among themselves, they haven’t added anyone to the party,” Monroe said.
Said Taylor: “Hopefully, in the future, all will be revealed.”
The City of Garland, Texas, last week told ERCOT it wants to mothball a 454-MW power plant for all but the summer.
| Tom Harpool Collection, University of North Texas Special Collections
The city’s municipal utility, Garland Power & Light, said it wants to run Gibbons Creek Generating Station only from June 1 to Sept. 30 each year, according to a notification of suspension of operations (NSO) filed Wednesday. The suspension would be effective Oct. 17.
Although Garland is a Dallas suburb, the 34-year-old coal-fired unit is located northwest of Houston. The plant is operated by the Texas Municipal Power Agency.
ERCOT stakeholders have until Aug. 2 to file any comments on the NSO as part of the standard reliability-must-run review.
The ISO also said on Thursday that it has determined a Union Carbide 40-MW gas-fired generator on the Texas Gulf Coast is no longer needed for transmission reliability needs and can be retired, effective Sept. 29. Union Carbide filed its NSO in June.
Gibbons Creak Generating Station | PMelton87, Wikipedia
The cogeneration unit went into service in 2000. As a private-use network unit, it is connected to the ERCOT grid, but the load is netted with internal generation and not directly metered by the Texas grid operator.
Stakeholders are at odds with MISO over some aspects of the RTO’s new interconnection queue rules during a time when the queue is beset by “unprecedented” backlogs.
RTO staff said the sheer volume of prospective projects is creating an overwhelming definitive planning phase (DPP) study cycle this year.
| MISO
“It’s the largest queue we’ve ever had — over 200 projects,” Patrick Brown, executive director of transmission asset management, said at a July 18 Interconnection Process Task Force (IPTF) meeting. MISO is reviewing project applications and will update the list of queue projects based on study findings by the end of July.
But multiple stakeholders have asked that queue implementation details be fleshed out in joint discussions involving either the Planning Subcommittee or Planning Advisory Committee. They contend that the RTO needs to more fully vet the policy and reliability implications of moving from one iteration of the queue process to the next.
Approved by FERC early this year (ER17-156), MISO’s new interconnection rules attempt to streamline an old process that was plagued by restudies and backlogs. (See FERC Accepts MISO’s 2nd Try on Queue Reform.) MISO Manager of Resource Interconnection Neil Shah said DPP studies coming out of the MISO West region are particularly heavy this year — “more than the current transmission system can accommodate” — and schedule delays are imminent. The RTO has so far this year received 85 requests representing nearly 12 GW of possible generation from that region alone.
| MISO
“The most practical thing to do is to prepare for delays. It’s really unprecedented, and the complexity of the studies will increase. … We just want stakeholders to be aware of how much it’s going to take to study this amount of megawatts,” Shah said.
Staff argued against stakeholders that were looking to change an already agreed-upon DPP timeline.
“Let’s not beat this dead horse,” Brown said. “I think we’ve had those discussions before. It was really incumbent on the stakeholders to decide if they want to accept those risks, and they’ve agreed to those risks. Stakeholders preferred to get it started right away.” He added that discussion was laid to rest in IPTF meetings during the spring.
MISO will clear the February 2016 batch of projects from the first part of the DPP before submitting any of the August 2016 entrants, a process that stakeholders favored over merging the two groups together in order to initiate the studies earlier — even if the separated approach carries an increased risk of restudy.
Shah said stakeholders decided in spring to continue with the changeover schedule, which was initially filed with FERC.
“Based on the feedback that we’ve received so far, we’re going to continue the course on the original schedule,” he said.
Shah noted that the probability of delays is high, even without a current delay. MISO is putting more of its own resources toward the study effort, he said.
The RTO is adding an additional 14 engineers to the approximately 100-employee queue team to handle the influx of studies, according to Brown. Eight Siemens engineers are working on studies for the possible additions in the MISO West region alone.
“There’s much consternation and gnashing of teeth among my finance team right now,” Brown said. “We still think there are going to be delays no matter how many bodies we throw at it.”
Geronimo Energy’s Randy Porter applauded MISO for being able to complete its schedule of studies on time so far this year. “I’d like to copyright a term: ‘study-tsunami,’” he said.
Stakeholders asked if MISO will compare the high number of projects to anticipated load growth to see if the projects will realistically be built.
MISO “would take a step back and look at the comprehensive picture” in subsequent studies occurring further into the queue, Shah said.
Below is a summary of the issues scheduled to be brought to a vote at the Markets and Reliability and Members committees Thursday. Each item is listed by agenda number, description and projected time of discussion, followed by a summary of the issue and links to prior coverage in RTO Insider.
RTO Insider will be in Wilmington, Del., covering the discussions and votes. See next Tuesday’s newsletter for a full report.
Markets and Reliability Committee
2. PJM Manuals (9:10-9:30)
Members will be asked to endorse the following proposed manual changes:
A. Manual 1: Control Center and Data Exchange Requirements. Revisions developed to comply with NERC reporting requirements. Transmission operators will be required to maintain certain data during outages, including bus voltages for all 345-kV stations or higher, and megawatt flows for tie lines and all lines 345 kV or higher.
B. Manual 11: Energy & Ancillary Services and Manual 18: PJM Capacity Market. Clarifies language on what is needed to qualify for exempt or bonus megawatts during performance assessment hours in PJM’s Capacity Performance construct. PJM says it needs certain data to determine how close generators follow its schedule. The data include values for economic minimum and maximum and emergency maximum.
3. Pseudo-tie Pro Forma (9:30-10:00)
Members will be asked to endorse proposed pseudo-tie agreements and Tariff and Operating Agreement revisions. The documents were developed to standardize pseudo-ties and minimize operating confusion. (See “OC Discusses Pro Forma Agreements for Pseudo-Ties, Dynamic Schedules,” PJM OC Briefs: July 11, 2017.)
4. Governing Document Revisions to the Limitation on Claims (10:00-10:10)
Members will be asked to endorse Tariff and Operating Agreement revisions to clarify the two-year limit on requests for billing adjustments.
Members will be asked to endorse updates to Manual 14B: PJM Regional Transmission Process and the Operating Agreement reflecting the change from the annual, 12-month Regional Transmission Expansion Planning cycle to an overlapping 18-month cycle beginning each September. The window for short-term projects will expand from 30 to 60 days. (See “RTEP Cycle Revisions Approved,” PJM PC/TEAC Briefs: July 13, 2017.)
Members will be asked to endorse proposed Tariff and Operating Agreement revisions to regulation market rules on performance scores, clearing and settlements that were endorsed by the Regulation Market Issues Senior Task Force and the MRC. The revisions change the rate for substituting traditional RegA and fast-response RegD. (See PJM Regulation Compensation Changes Cleared over Opposition.)
2. Pseudo-tie Pro Forma (1:45-2:15)
Members will be asked to endorse proposed pseudo-tie agreements and Tariff and Operating Agreement revisions. The documents were developed to standardize pseudo-ties and minimize operating confusion. (See MRC item 3 above).
While PJM stakeholders were meeting last week to consider yet more changes to the Reliability Pricing Model, public power representatives took their case to Congress, telling the House Energy and Commerce Committee on Tuesday that they should be released from participating in the increasingly complicated capacity construct.
American Municipal Power and Old Dominion Electric Cooperative told the committee that FERC should allow public power utilities to fill their needs through bilateral contracts or self-supply instead forcing them to participate in mandatory capacity markets. AMP — which provides power supply and other services to 135 members in Delaware, Indiana, Kentucky, Maryland, Michigan, Ohio, Pennsylvania, Virginia and West Virginia — also complained that PJM’s Capacity Performance rules undervalue the company’s new hydropower facilities.
AMP Senior Vice President and General Counsel Lisa McAlister and ODEC CEO Jack Reasor testified along with representatives from independent power producers NextEra Energy and Calpine, utilities Public Service Enterprise Group and Duke Energy, and demand response provider EnerNOC.
The two-hour hearing, titled “Examining the State of the Electric Industry through Market Participant Perspectives,” covered many issues. Rep. John Shimkus (R-Ill.) and ranking member Frank Pallone (D-N.J.) said the testimony would help them decide whether the Federal Power Act is in need of revisions.
PSEG made a pitch for financial support for its New Jersey nuclear plants, which Calpine and NextEra strongly opposed. Duke asked for reforms to the Public Utility Regulatory Policies Act and a “shot clock” for regulatory approvals of pipelines and other infrastructure projects.
Former FERC Chairman Joseph Kelliher, now executive vice president for NextEra, also offered his company’s answers for the questions that Energy Secretary Rick Perry asked in commissioning a study of renewable resources’ effect on the reliability of the grid. It is market fundamentals — not public policies, he said — that are the primary drivers of “baseload” plant retirements, and there is “no evidence” that those retirements are threatening reliability.
No RTOs or ISOs were represented in the hearing. They will get their chance to speak before the committee in a second hearing on July 26. But PJM was invoked frequently, and generally not favorably.
PJM Capacity Market under Fire
McAlister’s 21-page written testimony — more than twice as long as any other witness’ — reiterated public power’s longstanding complaints with PJM’s capacity construct, calling it a “complex rules-driven administrative mechanism” that “relies on such distinctly non-market features as an artificial demand curve, price caps and minimum offer price requirements, and obstacles to competition from certain types of resources.
“RPM is a ‘market’ in name only,” she continued. “And, as time has gone on, fewer and fewer PJM market participants use that term to describe it.”
ODEC also criticized RPM, saying its experience “has been mixed at best.”
Reasor quoted from FERC’s April 2006 order approving RPM. “After [load-serving entities] have had the opportunity to procure capacity on their own, it is reasonable for PJM to procure capacity in an open auction at a time when further delay in procurement could jeopardize reliability,” FERC said, adding, “This, however, should be a last resort.”
Although the annual capacity procurement is still called the Base Residual Auction, “repeated and significant design changes have made RPM more complex and costly and have undermined the ability of load-serving entities to use their resources to meet their capacity obligations,” Reasor said.
The 2016 BRA was the first PJM capacity auction with no rule changes from the prior year, following 24 significant FERC filings to revise RPM between 2010 and 2016, Reasor said, quoting PJM. The last major change, the introduction of Capacity Performance, imposes “onerous performance requirements” on capacity resources, he said.
New Hydro Dissed by CP
McAlister also complained about CP, saying it undervalues the $3 billion AMP spent to install 300 MW of hydroelectric facilities on existing dams on the Ohio River because the projects cannot guarantee continuous, yearlong operation. “This is the case because AMP cannot control the river flows and cannot practically back up the hydroelectric plants with an alternative generation resource,” McAlister said. “In making PJM’s capacity construct less flexible, CP also has made it less capable of integrating the diversity of resources that may be an element of implementing important state policies.”
McAlister said PJM “needs a resource adequacy construct that is robust enough to withstand the effect of external events without the need to adopt another set of complex rule changes in response to each event.”
She and Reasor said LSEs should be permitted to fulfill most or all of their capacity needs through bilateral contracts, with the BRA relegated to a truly residual auction to fill any shortfalls. (See related story, PJM Stakeholders See Capacity Auction Flaws, Offer Solutions.)
As a “second-tier alternative,” McAlister said, public power’s ability to self-supply their own loads should be restored by reducing the role of the minimum offer price rule (MOPR).
Transmission Costs
AMP also complained about transmission costs, saying four of its members’ transmission zones have seen annual revenue requirements double or triple between 2009 and 2016.
AMP’s and ODEC’s complaints regarding the transmission owners’ handling of supplemental projects — those not required for compliance with PJM’s reliability, operational performance or economic criteria — prompted FERC last August to issue an order to show cause finding that the TOs’ procedures were not in compliance with FERC Order 890 (EL16-71).
FERC said the evidence indicated that some TOs are “identifying — and even taking steps toward developing — supplemental projects before providing any opportunity for stakeholders to participate in the development of those projects through the PJM [Regional Transmission Expansion Plan] process.”
The order resulted in a hiatus in a stakeholder initiative, the Transmission Replacement Processes Senior Task Force, pending the TOs’ response. Although the TOs insisted they are in compliance with Order 890, they proposed a Tariff amendment providing additional detail on supplemental projects. FERC didn’t rule on the TOs’ response before losing its quorum in February.
“AMP supports appropriate transmission infrastructure build-out to replace aging infrastructure,” McAlister told the House committee. “However, there needs to be more transparent transmission planning, equitable treatment, better oversight to ensure the most cost-effective and efficient grid expansion, and rates of return that reflect current economic conditions and risks.”
AMP asked Congress for “enhanced” oversight of FERC “to ensure that [the commission] is responsive to the real needs of consumers” by making low costs “a central part of the RTO mission, in addition to promoting electric system reliability.”
McAlister also said Congress should ensure that RTO governing boards “are truly representative and open [and] transparent” with open board meetings. While the boards of MISO, SPP, ERCOT and CAISO meet in open session, PJM’s board meets in private, as does ISO-NE’s and NYISO’s.
The hearing also considered proponents and opponents of subsidizing nuclear plants. Tamara Linde, PSEG’s executive vice president and general counsel, repeated the company’s threat to retire its 3,500-MW Salem and Hope Creek nuclear plants in southern New Jersey. The plants, which are licensed until at least 2046, produce about 45% of the state’s electricity.
Linde said FERC should order PJM and other RTOs to “immediately” change their market rules to “preserve the diversity and resiliency of the nation’s electric generation resource mix.”
“Markets weren’t designed to drive to fuel diversity as an outcome, because fuel diversity in the generation fleet was always presumed,” she said.
Linde also said the U.S. nuclear supply chain should be considered “critical infrastructure, just as we regard our national highway system, electric grid and drinking water.”
Opposing nuclear subsidies were NextEra’s Kelliher and Calpine’s Steve Schleimer, senior vice president for government and regulatory affairs. Schleimer said competitive markets are threatened by both the zero-emission credits for nuclear plants in New York and Illinois, and New England states’ long-term procurement of renewables.
“If not addressed, out-of-market subsidies will undermine competition, investment will dry up, and these states will be back in the business of mandating when, where and what type of new generation will be built through long-term ratepayer guarantees, which is exactly the structure we moved away from several decades ago,” he said.
“A ‘hybrid’ market, where a state relies in part on the competitive wholesale electricity market to meet its resource needs, but also retains the right to select and subsidize preferred generation resource types to meet certain public policy goals, does not work and destroys all new competitive investment,” Schleimer said.
CAISO’s Lesson
He said the risk is playing out in CAISO, where he said the state’s “long-term contracting practices have decimated the competitive market.”
“It has led to the paradox that while retail rates are amongst the highest in the country as a result of these contracting mandates, wholesale prices are so low that the economic viability of the remaining generation that is dependent on competitive wholesale markets (generally existing conventional generation resources acquired or built when the market was competitive) is increasingly threatened.”
Alex Glenn, Duke’s senior vice president for state and federal regulatory legal support, had five requests to Congress, including swift confirmation of FERC nominees; the retention of the federal income tax deduction for interest expenses; “a reasonable ‘shot clock’ for actions on permit applications” for critical infrastructure projects; and a rewrite of PURPA to eliminate above-market must-take purchase obligations.
Glenn also said Congress should amend the SAFETY Act “to expressly include cyberattacks, and improve the process to obtain a security clearance so that we can increase the information-sharing capabilities between public and private entities.” Including cyberattacks under the third-party liability protections in the act would allow utilities and first responders to help recovery from an attack without the threat of “of protracted lawsuits in multiple jurisdictions,” he said.
In contrast to Duke’s lengthy wish list, Kenneth D. Schisler, vice president of regulatory affairs for EnerNOC, had only one request. Schisler thanked federal policymakers for removing market barriers to DR and said “it is vital” that FERC find a way to maintain competitive markets while respecting state policies. “Our only ask here today is that you continue to recognize demand response and its importance to our national energy strategy,” he said.
VALLEY FORGE, Pa. — PJM’s Capacity Construct Public Policy Senior Task Force has been working at a torrid pace to develop potential rule changes in time for next year’s capacity auction.
After little more than four months of meetings, PJM and stakeholders have offered four proposals to fix what many see as flaws in the RTO’s capacity construct. The main issue is how to accommodate state actions — such as energy credits or tax incentives, which subsidize certain generation types — without allowing them to influence clearing prices.
The RTO envisions a two-stage auction in which the first stage includes subsidized units and creates a “suppressed capacity price” using PJM’s standard variable resource requirement (VRR) demand curve. The second stage replaces subsidized units with a “reference price offer reflecting what would be a competitive offer from a unit of that type and vintage.” This would create a higher “restated price” more in line with pure competition that all cleared units would receive, unless states instructed PJM to pay its subsidized units less. Units that didn’t clear under the “suppressed” price would not receive capacity payments, even if they clear under the “restated” price.
| NRG
LS Power and NRG Energy responded at the task force meeting July 17 with proposals to tweak the two-stage approach. Both were designed to address those units that slipped between the auctions, which NRG referred to as “in-between” units. LS took the route of adjusting price, while NRG focused on adjusting quantity.
LS calls its proposal the “clearing price impact election model.” It factors the output of subsidized units into the second stage, resulting in a lower subsidized clearing price. Generators would have to elect when they submit their bids whether they would accept a lower subsidized price, which PJM would estimate before the auction. Those who won’t accept the lower price don’t clear, and the final clearing price would be adjusted upward as their output is eliminated from the supply. This would discourage units from creating price suppression by bidding low, LS argues.
NRG’s approach would also determine prices with and without subsidized units. Subsidized units would receive the subsidized price, and unsubsidized units would receive the unsubsidized price. The “in-between” units that clear the auction in the unsubsidized price but not in the subsidized price would clear and receive the unsubsidized price. The quantity of all offers would be reduced proportionally to ensure the entire auction cost is no higher than the total for the auction using the unsubsidized price.
Other Perspectives
Two other stakeholders took drastically different approaches.
Exelon, which has been battling for more than a year to secure state subsidies for some of its nuclear fleet, argued why such subsidies shouldn’t be mitigated in PJM’s auctions. More than 10 GW of resources “receive longstanding state support to enter/remain the market,” Exelon says, with the largest category being small- to medium-sized coal plants in regulated states.
“Resource adequacy objectives have been met at a reasonable cost despite the material impact on the marginal clearing price,” according to Exelon’s report. “Mitigation is unnecessary.”
“This is a very complex topic and we tried to bring some data and performance results into the conversation, realizing that other stakeholders may have different perspectives,” said Exelon’s Sharon Midgley, who presented the proposal.
Last Tuesday, the second day of the two-day task force meeting, American Municipal Power called for a smaller role for the Reliability Pricing Model, with public power permitted to meet most of their capacity needs through long-term bilateral contracts. AMP’s Ed Tatum argued that RPM is an “administrative construct … not a market,” and that PJM and its stakeholders “have to stop focusing on price and let a market do its thing.” Since 2010, PJM has made at least 27 major filings changing RPM, he said.
| Exelon
AMP’s plan would hinge on annual determinations of capacity obligations for load-serving entities, with a capacity auction several months before the delivery date, rather than three years. It would also eliminate the single clearing price created by the VRR curve in favor of a mechanism to match individual buyers and sellers. (See related story, Public Power Takes its PJM Gripes to Congress.)
| NRG
Several RPM structures would be maintained, such as resource must-offer requirements, the RTO reliability requirement, demand response participation and the Capacity Performance system of bonuses and penalties. The group also proposed a penalty on LSEs that fail to secure necessary capacity.
Stakeholders from both supply and demand pushed back, largely concerned that the plan would impede price transparency.
“Those customers who are signing up specifically to hedge their capacity costs, if they don’t know what the price that they’re paying is, that’s very difficult for them to hedge,” EnerNOC’s Katie Guerry said.
Joe Bowring, PJM’s Independent Market Monitor, had a much simpler solution.
“You can’t be partly regulated and partly not. You have to choose, and states have a whole range of options,” he said. “If states want to take it back [and fully regulate the industry], that is absolutely within their authority. What they shouldn’t do is take actions that are not in their authority. … If you subsidize two or three particular units … you’re suppressing the price of energy compared to what it would have been and you’re putting other units that are now economic at risk. That’s why I continue to repeat that subsidies are contagious.”
He said there’s no sense in “trying to work out complicated ways to make subsidies work in markets when they really can’t.”
“To me, the problem that has been identified is that competition is working,” Bowring continued. “Competition is a nasty business. Competition puts people out of business on a regular basis. I think it would be very difficult for the PJM markets in their current form to adapt to any more fully regulated states. … It would mean a significant change because the current structure of fully competitive markets is not compatible with a mix of generators with revenues based on cost-of-service regulation and generators with revenues dependent on markets.”
After the meeting, Bowring submitted recommendations that provide a definition for subsidies and call for developing an extended minimum offer price rule for all subsidized units that would be reviewed annually.
The task force has another two-day session planned for Aug. 2-3, at which Bowring’s recommendations and an update to the proposal from LS will be discussed. Other meetings are scheduled for Aug. 23, Sept. 11 and Sept. 26. The task force’s issue charge calls for any results to be delivered by the end of the year.
MISO’s Independent Market Monitor last week gave board members an explanation of the most pressing of the nine new recommendations contained in this year’s State of the Market report, which RTO staff are reviewing for potential inclusion in its annual Market Roadmap of market improvements.
Jeff Bladen, MISO executive director of market design, said the RTO will present its response to the report in September. Under its Tariff, MISO has 120 days to reply after the delivery of the report. Some of the recommended changes had been discussed in front of board members before, though the report was released early this month. (See Monitor Recommends 9 New MISO Market Changes.)
Monitor David Patton said he and the RTO have generally been on the same page over the years when it comes to his market recommendations. “I don’t sense that we’ve disagreed a lot; there are some recommendations that aren’t feasible,” Patton said during a July 20 Markets Committee of the Board of Directors conference call.
However, Patton said he sometimes disagrees with MISO’s prioritization and ranking of market projects on the Market Roadmap: The RTO tends to prioritize market efficiency and cost above all, while he champions cost, benefits and reliability. The two will return to the committee to give their takes on prioritization when the list is finalized in winter, he said.
MISO South Emergency
Patton addressed MISO’s April 4 maximum generation emergency in MISO South, the first in more than a decade.
The Monitor said that new penalties on non-responsiveness, and improved communication protocols, drove load-modifying resource participation to more than 80% from just 50% during the last emergency in 2006. (See 4 LMRs Face Penalties after MISO Max Gen Emergency.)
Patton repeated his contention that the emergency might have been avoided altogether if MISO had expanded authority to coordinate transmission and generation outages. Under current rules, the RTO can only recommend a revised outage schedule when an analysis shows that reliability will be in jeopardy.
“Our recommendation is to expand that authority to address the economic inefficiencies of having poorly coordinated outages,” Patton said.
Local Reserve Product
Patton recommends that MISO develop a 30-minute local reserve product for voltage support, local reliability and subregional capacity. Some areas do not have resources that can start within 30 minutes to restore supply after a contingency, Patton said, resulting in high uplift costs. He also said that when the Midwest-to-South transmission constraint binds after a contingency, MISO also must incur uplift charges just to secure subregional capacity needs.
“If we had a product, we’d set shortage pricing and potentially reduce our revenue sufficiency guarantee by a large margin,” Patton said. He said that the pricing would require its own settlement. “You would only deploy it after a major contingency, which might only be a few times a year.”
“In most of the eastern RTOs, a 30-minute product is in use regionally and even in local areas,” Patton said, adding that that even if MISO built its own transmission to relieve the Midwest-to-South constraint, a reserve product would still be useful for local needs.
“I think you’re personally on the right track here,” Director Thomas Rainwater said.
M2M Coordination
MISO’s market-to-market coordination could also use improvement, said Patton, who recommends MISO, PJM and SPP devise a process to hand off flowgate control when another RTO’s flows are dominating a constraint.
More than $238 million worth of congestion could have been more efficiently managed in 2016 through better M2M procedures, he said.
“Increasingly, market-to-market coordination is becoming important because of pseudo-ties and the increased implementation of wind that fluctuates heavily and creates constraints. The ability to coordinate and move generation on our neighbors’ constraints … is increasingly beneficial and cost effective,” Patton said. He suggested that MISO develop a joint operating agreement with the Tennessee Valley Authority for coordinating congestion management.
PJM’s and SPP’s effects on MISO’s systems are large enough that MISO should have identified them as a M2M constraint. Because MISO has not done so, it receives no compensation when PJM or SPP dominate flows on its system.
Shortage Pricing
Patton also said MISO’s shortage pricing method needs improvement, recommending the cap on the value of lost load (VoLL) be increased to almost $12,000/MWh to create a more sloped contingency reserve demand curve.
| Potomac Economics
MISO’s proposed reserve demand curve — filed in May to comply by Dec. 1 with FERC Order 831 (ER17-1571) — is much flatter, hovering at $2,100/MWh for much of the curve unless MISO clears less than 8% or more than 96% of its requirement level. MISO’s flatter approach results in “overstated shortage prices for small shortages and understated shortage prices for larger shortages,” Patton said. MISO’s current curve looks similar to the proposed option but carries a $1,100/MWh value for most of the curve unless less than 89% or more than 8% of the requirement clears.
According to Patton, there is disagreement among industry studies on VoLL. “Our personal view is that you should choose a value at your highest load, and that’s why we ended up at $12,000,” he said.
Capacity Auction Rules
Patton expressed concern over MISO’s “essentially zero” $1.50/MW-day footprint-wide clearing price in the 2017 capacity auction.
“In the current context, I think what I would say is the decision not to move forward with a competitive retail solution … is something we’d like MISO to reconsider over time,” Patton said. In addition to finding a solution for the RTO’s competitive load areas, Patton still advocates the use of a sloped demand curve in the Planning Reserve Auction.
“When we have hot topic discussions, we have some sectors that pound the table in favor of a sloped demand curve, and other sectors less so,” Director Baljit Dail observed. He asked why MISO has yet to instate a sloped demand curve in the auction.
“To be honest, it’s been a journey. I always thought it’d be easier with MISO because most of the capacity in MISO is self-supply through vertically integrated utilities. In a sense, the capacity prices don’t matter,” Patton said.
Awaiting MISO Response
Board members said that they had questions but would hold off on asking them until they could review MISO’s response to the recommendations.
“There are some questions that sound like we’re waiting to ask MISO management, ‘This is a very good idea. Why hasn’t this been done?’ and I suspect we’ll get a very thoughtful response,” Director Paul Bonavia said.
Richard Doying, MISO executive vice president of operations, said the RTO should have a “fairly thorough” response by September, but more analysis may be needed.
“For some of these, we may have an indicative response and would wait until October for a full evaluation,” Doying said.
“Congratulations, you’ve worn us down,” Bonavia joked to Patton before ending the two-hour-plus conference.
California officials Thursday cleared the Aliso Canyon natural gas storage facility to resume injections, even as momentum builds among lawmakers, regulators and the public to permanently close the site of the massive methane escape near Los Angeles.
The methane leak caused by a broken pipe casing at the 86-Bcf storage facility owned by Southern California Gas was discovered in October 2015 and plugged in February 2016.
State engineering and safety officials said that after months of “rigorous inspection,” they “have concluded the facility is safe to operate and can reopen at a greatly reduced capacity in order to protect public safety and prevent an energy shortage in Southern California,” according to the California Public Utilities Commission. State legislation required the PUC and Division of Oil, Gas and Geothermal Resources to clear the facility for operation before gas injections could resume there.
PUC Executive Director Timothy Sullivan said: “After careful review of testing results, our safety teams have confirmed the integrity of the wells at this facility. Out of an abundance of caution and consideration for public safety, storage capacity will be restricted to approximately 28% of the facility’s maximum capacity — just enough to avoid energy disruptions in the Los Angeles area.”
Aliso Canyon Well Head | Earthworks
State Oil and Gas Supervisor Ken Harris issued an order laying out testing requirements at the facility after injections resume. About 60% of the wells at Aliso Canyon have now been taken out of operation and isolated from the facility, and remaining wells were cleared during testing, officials said. Active wells now have real-time pressure monitors and will be subject to aerial monitoring. The wells also have new steel tubing and seals.
The finding came the same day the head of the California Energy Commission wrote PUC Chairman Michael Picker, calling for the facility to be permanently closed. He said Gov. Jerry Brown asked him to make plans for the facility to be permanently shut down.
“My staff is prepared to work with the CPUC and other agencies on a plan to phase out the use of the Aliso Canyon natural gas storage facility within 10 years,” CEC Chairman Robert Weisenmiller said in the letter.
Weisenmiller said that closing the facility “is no small task and the recommendation to close the facility is not one that I take lightly or without thoughtful consideration.” But he said reliability worries could be addressed through investing in renewable energy, energy efficiency, electric storage and other tools.
The PUC will continue its proceeding focused on the future of the facility. (See Study to Weigh Aliso Canyon Shutdown.) The Governing Body of the Western Energy Imbalance Market (EIM) also recently approved the extension across the EIM footprint of gas constraint measures developed by CAISO to address reliability concerns stemming from the Aliso Canyon outage, although the plan is designed to apply to potentially similar circumstances arising at other storage facilities. (See EIM Leaders Endorse CAISO Gas Constraint Measure.)
SoCalGas welcomed the decision in a statement Thursday. The company had warned of reliability concerns stemming from the loss of the facility and in November 2016 requested permission to resume injections.
State Senator Henry Stern: “There is no rush to re-open Aliso Canyon”
“Aliso Canyon is an important part of Southern California’s energy system, supporting the reliability of natural gas and electricity services for millions of people. SoCalGas has met — and in many cases, exceeded — the rigorous requirements of the state’s comprehensive safety review,” the company said.
On Wednesday night, State Sen. Henry Stern (D) tweeted that the “proposal to re-open #AlisoCanyon before we know what caused the leak and before earthquake and fire risks studied is premature & unnecessary.”
DENVER — As it comes to grips with the migration of 430 MW of West Texas load to ERCOT, SPP is confronting the possibility that as much as 1,300 MW of additional load could leave its system.
SPP members are encouraging the RTO to explore the reasons for the departures — and how to prevent them.
East Texas member Rayburn Country Electric Cooperative last month opened a project with the Public Utility Commission of Texas to “identify issues pertaining” to transferring its load and portions of its facilities into ERCOT (Docket 47342).
Despite its membership in SPP, only 15 to 20% of Rayburn Country’s load (about 150 MW) sits in the Eastern Interconnection. ERCOT estimates it will cost $38 million — primarily for a new 345-kV substation, a 138-kV switching station and the expansion of several 138-kV lines — to connect the co-op’s SPP load with the Texas Interconnection.
Rayburn Country owns and operates 160 miles of transmission in SPP, of which it proposes to move 130 miles into the ERCOT footprint, adding to the 207 miles of lines it already owns there.
The co-op determined that consolidating its load into ERCOT will give it access to “a more liquid and competitive wholesale power market, improved reliability, and elimination of cross-grid issues such as multiple NERC reliability standard audits and differing regional practices.”
An SPP task force has identified several other potential Texas entities with a medium-to-high risk of transferring an additional 1,100 MW of load into ERCOT, not including Lubbock Power & Light and the aforementioned 430 MW.
At its recent annual retreat, SPP’s Strategic Planning Committee considered whether it should “develop incentives or other mechanisms” to prevent future member migrations, Vice President of Process Integrity Michael Desselle said last week during an SPC meeting.
Who Pays?
“The strategic issue of who pays for what is actually fairly important,” said Oklahoma Gas & Electric’s Jack Langthorn, who chaired a task force studying the implications of LP&L’s departure. “When you lose load, should the costs go with it? When entities come in or leave, who pays for what?”
“These strategic questions remain and won’t go away,” said SPC Chair Mike Wise, Golden Spread Electric Cooperative’s senior vice president of regulatory and market strategy. “The lack of [retention] incentives we have in SPP needs to be resolved.”
The costs would be significant for Golden Spread and Southwestern Public Service, which currently serves Lubbock’s load.
A recent joint study between SPP and ERCOT indicates that the transfer of LP&L would increase annual transmission revenue requirement (ATRR) payments for 17 of SPP’s 18 transmission zones by an average of 1.3%. Zonal rates in the SPS zone would decline about 9.3% because of an approximate 10% drop in load, but the zone’s remaining load would see a regional-allocation increase similar to other SPP zones on a cost-per-megawatt basis, or $217/MW.
“What we’re really talking about is $14 million being reallocated within the SPS zone,” said Bill Grant, SPS’s regional vice president of regulatory and strategic planning. “It’s not insignificant by any means.”
“I am a big load inside the SPS zone. If this load leaves the zone, it increases my [transmission] costs,” Wise said.
Dueling Studies
SPP and ERCOT performed production-cost analyses for the years 2020 and 2025 to evaluate the effects of moving part of the LP&L system. SPP would see fuel costs drop $64 million to $86 million in its footprint and $61 million to $89 million in Texas in 2020. Those ranges increase to $71 million to $105 million and $68 million to $113 million, respectively, in 2025.
ERCOT’s portion of the study found its production costs would increase as much as $77 million in 2020 and $74 million in 2025. The ISO says that increase will be offset by using the LP&L interconnection to unlock wind energy currently trapped in the Texas Panhandle. (See “LP&L Study: Production Costs Increase,” ERCOT Board Briefs.)
| ERCOT
The Texas grid operator last year conducted a separate study showing it will cost $364 million to integrate LP&L, mostly through construction of 141 miles of new 345-kV lines. SPP’s study found it would need to spend $5.1 million on additional transmission projects to compensate for the loss of LP&L’s load, but another $1 million of upgrades could be deferred or avoided.
ERCOT’s study found the new facilities would increase grid stability in the Panhandle, while SPP determined any reliability concerns could be mitigated. The joint study predicted “minimal impacts” on ancillary service procurement quantity and markets, and on congestion rights and their markets.
LP&L announced in 2015 that it planned to disconnect its load from SPP and join ERCOT in June 2019 (Docket 45633). The PUC last summer asked the grid operators to conduct coordinated studies focused on a cost-benefit analysis for ratepayers. (See Texas PUC OKs ERCOT, SPP Studies on Lubbock Move.)
Grant encouraged the SPC to compare the two studies and “really start digging into the issues of why an entity might want to leave. There’s no better way to put it than Tariff arbitrage. That’s what it is.
“I don’t know what you can do to stop that,” Grant said. “If there are any savings to an individual entity, it’s the way they’re treated under their individual tariffs. If [zonal placements don’t happen fairly], you don’t get the added value of having transmission requirements in your zone.”
LP&L said it will next month file a contested case with the PUC slated to begin in May 2018 and has asked the commission to discuss the matter during its July 28 open meeting. The municipality said this timeline would allow it to successfully integrate with ERCOT before a “bridge agreement” extending its SPS power contract expires in May 2021.
