BloombergNEF’s annual Sustainable Energy in America Factbook is a smorgasbord of data that energy policy nerds have hungrily consumed since the company started publishing it eight years ago.
For its 2020 edition, released last week, BNEF combined last year’s data with a look back over the last decade, “10 extraordinary years [in which] the U.S. fundamentally overhauled how it produces, delivers and consumes hydrocarbons, electrons and heat.”
U.S. electricity generation by fuel type | BloombergNEF
Natural Gas & Coal
Domestic natural gas production rose more than 50% during the decade and 8% in 2019, pushing the U.S. from a net importer to a net exporter. The gas distribution pipeline network grew from 2.09 million miles in 2009 to 2.24 million through 2018 (the last year for which there is complete data).
Gas prices dropped to 2016 levels last year, with Henry Hub natural gas trading below $3/MMBtu every month except January.
Power sector demand for natural gas rose 60% as gas-fired generation’s share jumped from 24% to 38% over the decade. Coal’s share declined by almost half, from 45% to 23%. About 12 GW of coal-fired generation shuttered in 2019 and another 14 GW of retirements have been announced for the next three years.
Renewables & Storage
Generation from renewables spiked 77% during the decade, fed by new utility-scale wind and solar projects and rooftop solar. Renewable capacity doubled over the same period, with installed wind tripling to 108 GW and solar increasing 80-fold to 75 GW. The U.S. is second only to China in renewable capacity.
Last year was the second biggest ever for new non-hydro renewable energy capacity, with 20 GW commissioned, most of it wind and solar. Wind generation rose to 302 TWh in 2019 from 273 TWh the year before, surpassing hydro generation, which dropped from 293 TWh to 276 TWh. Renewables powered 18% of electric consumption in 2019.
U.S. electric generating capacity build by fuel type | BloombergNEF
“In a potential harbinger, U.S. hydro, wind, solar, biomass, geothermal and waste-to-energy produced more than the country’s fleet of coal-fired power facilities in April 2019,” surpassing coal for the first time, BNEF said.
Corporations — including oil companies looking to reduce extraction-related emissions — signed a record 14 GW of bilateral renewable energy power purchase agreements last year.
In the last two years, projects that pair renewable technologies with large-scale batteries have become economically viable. (See related story, Energy Storage: All Grown Up?)
From 2010 through 2018 (the last year for which complete data are available), investor-owned utilities invested an average of $18.9 billion a year (2018 dollars) in transmission, nearly double their inflation-adjusted spending for the previous decade. Renewable developers, however, say they need far more transmission to move power to load centers from wind- and solar-rich regions.
Efficiency, Economy, Emissions
U.S. energy demand increased little over the decade despite 10 consecutive years of economic growth since 2009. While U.S. gross domestic product rose 25%, total energy use was up only 6.6%.
In 2019, energy productivity — the ratio of GDP growth vs. energy consumption growth — rose 3.3% as GDP grew by 2.3%, while energy consumption declined 1%.
Lower energy costs have contributed to low inflation, with U.S. households now spending less than 4% of their average monthly income on energy spending, down from 5.1% 10 years ago.
Meanwhile, as of 2018, 3.5 million people were working in the energy efficiency, energy storage, renewables, nuclear and natural gas industries.
Greenhouse gas emissions from power plants dropped by nearly 25% for the decade, making the sector the second largest emitter, behind transportation. Less extreme weather contributed to a 2.8% drop in power consumption in 2019. “Lower top-line demand coupled with the general move toward a cleaner power matrix caused power sector-related emissions to crater by a rather incredible 7.8%,” BNEF said.
Jobs in electricity generation | BloombergNEF
However, it said climate change is causing higher high and lower low temperatures, increasing air conditioning and heating demand. “If these trends persist, increased energy consumption can make efforts to reduce energy sector emissions more difficult,” it said.
Transportation sector emissions rose 5% during the decade despite the growth in electric vehicles. U.S. consumers now have a choice of 44 pure battery electric models and 35 plug-in hybrid electrics. EV sales totaled 1.4 million for the decade but dropped 11% in 2019 versus 2018. EVs represented only 1.8% of U.S. vehicle sales for the year. (See related story, Spotty EV Growth, TOU Enrollment Challenges States.)
Nine states increased their renewable portfolio standards in 2019, and states such as Washington, Nevada and New Mexico set zero-carbon, energy efficiency and fuel efficiency targets.
ERCOT CEO Bill Magness last week told the Board of Directors that the grid operator finished 2019 with a net positive variance of $35.4 million, boosting the pool of funds to implement real-time co-optimization (RTC).
ERCOT CEO Bill Magness | ERCOT
Magness said during the board’s Feb. 11 meeting that a preliminary budget review indicated a 13.3% increase in revenues and a 3.4% decrease in expenditures. He credited a $19.2 million increase in interest income and a $6.5 million increase in system administrative fees for much of the positive variance.
Interest income was coming in over budget as a result of higher balances and rates, Magness told the board in April. The unexpected revenue has been set aside to fund an RTC development pool, now at $52.5 million. ERCOT has estimated it will cost at least $40 million to add RTC to the market.
Magness said the administrative fee variance benefited from warmer-than-normal weather from August into October. September provided $2.4 million and August $1.3 million in actual revenue above budget. October and November accounted for $800,000 and $700,000, respectively, in overages.
October “is kind of what you would expect,” Magness said. “September was the really unusual thing.”
ERCOT’s 2019 financial summary, variance to budget | ERCOT
ERCOT’s load continues to grow, with a 2% increase in annual energy usage between 2018 and 2019, after a 5% increase between 2017 and 2018. Over the past decade, energy use is up 20.4%, from 319,097 TWh to 384,040 TWh. The decade before, energy use was up 7.7%.
“[Growth] was as substantial as it felt like, and we continue to see growth,” Magness said.
Real-Time Co-optimization Team Finalizes Scope
ERCOT’s Matt Mereness thanked “all y’all” as he secured the board’s approval of the final batch of RTC key principles that will guide the grid operator’s addition of the market tool into its energy market.
RTC procures both energy and ancillary services every five minutes to find the most cost-effective solution for both requirements. (See “Committee Endorses Final Real-time Co-optimization Principles,” ERCOT Technical Advisory Committee Briefs: Jan. 29, 2020.)
ERCOT’s Matt Mereness briefs the board on real-time co-optimization. | ERCOT
Mereness chaired the Real-Time Co-optimization Task Force, which wrapped up nine months of work by producing a 44-page document that defines the principles, or boundaries, that staff and stakeholders are working toward.
“It’s been painful but focused,” Mereness said of the group’s 16 meetings. “Collaborative, not always perfectly unanimous, but working together to find solutions. One secret that made it work is we had a single forum. All the smart people were in the room working on it.”
Congratulated by board Chair Craven Crowell, Mereness responded, “It takes a village.”
Staff plan to file a set of Nodal Protocol revision requests (NPRRs) implementing RTC in March. The task force will serve as a clearinghouse to address language changes and comments, with a goal of submitting all NPRRs to the Protocol Revision Subcommittee for its consideration in November. If everything stays on schedule, the Technical Advisory Committee and the board will see the final NPRRs in November and December.
According to its schedule, RTC will be added to the market by mid-2024 before a planned update to ERCOT’s Energy Management System.
Helton, Lange Re-elected to TAC Leadership
The board approved staff’s determination that developing systems to enable economic dispatch over DC ties between the grid operator and other systems would be “prohibitively complicated and expensive” and is not “presently feasible.” Staff said existing systems and processes are sufficient enough to manage congestion caused by DC ties.
“A five-minute dispatch would be technically and jurisdictionally a challenge,” Mereness said.
ERCOT had been directed by Texas’ Public Utility Commission to study and determine whether some or all DC ties should be economically dispatched or whether implementing a congestion management plan or special protection scheme would more reliably and cost-effectively manage congestion caused by DC tie flows.
Nick Fehrenbach, manager of regulatory affairs and utility franchising for the city of Dallas, pointed out the Southern Cross project is a “commercial venture for economic benefits” and raised concerns about the import and export of power outside economic dispatch.
“This troubles me,” Fehrenbach said. “I don’t know the next project of this nature, but this is something we need to resolve in the long run.”
Mereness said that ERCOT has changed its scheduling of DC ties. As their ramp comes in, it is offset by the grid operator’s economic dispatch.
Leadership Re-elected
In other action, the directors re-elected Crowell as chair, former PUC Commissioner Judy Walsh as vice chair and Magness as CEO, and ratified ERCOT’s officers.
The board’s consent agenda, which passed unanimously, included 16 NPRRs, single revisions to the Nodal Operating Guide (NOGRR) and Verifiable Cost Manual (VCMRR) and a system change request (SCR):
NPRR826: creates a new process for determining the mitigated offer cap for reliability-must-run (RMR) resources.
NPRR838: revises the RMR process by removing the requirements for units to submit operations and maintenance estimates and for RMR resources to submit quarterly O&M updates.
NPRR955: defines a limited-impact RAS to accommodate NERC Reliability Standard PRC-012-2.
NPRR963: allows an energy storage resource’s (ESR) components to be considered in aggregate for generation resource energy deployment performance scoring, controllable load resource energy deployment performance scoring and settlement of base point deviation charges.
NPRR964: removes from the RMR process the term “synchronous condenser unit” and its related agreement.
NPRR967: removes the 10-MW limit for limited-duration resources.
NPRR970: clarifies the fuel-dispute process for reliability unit commitment (RUC) make-whole payments.
NPRR971: updates the energy offer curve’s cost cap value.
NPRR974: requires ERCOT to include additional data about the amount of projected capacity available in the short-term system adequacy report.
NPRR977: requires ERCOT to post a report of canceled RUCs to the market information system.
NPRR978: incorporates revisions to address recent changes on the PUC’s resource adequacy reporting rules.
NPRR980: changes how forced outages longer than 180 days are treated in ERCOT’s Capacity, Demand and Reserves report.
NPRR982: clarifies that a deployed block-load transfer will be appropriately compensated.
NPRR985: modifies the time period used to compute the forward adjustment factor components of the total potential exposure calculation and clarifies that the three forward weeks commence on the applicable operating day, rather than following the operating day.
NPRR986: gives ESRs more flexibility in updating real-time energy offer curves and bids.
NPRR988: corrects NPRR929’s intended implementation by clarifying that conditions in its language are necessary for determining whether a point-to-point obligation with links to an option bid is eligible to be awarded.
NOGRR183: aligns the Nodal Operating Guides with NERC’s remedial action scheme reliability standard.
SCR806: adds resource-specific offer information to all individual disclosure reports on ERCOT’s website.
VCMRR026: removes an appendix to align the manual with NPRR970’s proposed protocol language and NPRR617’s revisions.
WASHINGTON — Jason Burwen, vice president of policy for the Energy Storage Association, took his audience down memory lane Wednesday, recalling the industry’s growth since he joined the organization in 2015.
At the time, he told an audience of 200 at ESA’s annual Energy Storage Policy Forum, there was only 200 MW of non-hydro storage on the grid, virtually all in front of the meter and less than one hour in duration. The market was almost entirely frequency regulation.
Just five years later, there is more than 1,500 MW of storage online, one-third of it behind the meter, with some batteries capable of injecting energy for up to eight hours. In addition to providing ancillary services, it is also seeking roles as capacity and transmission. It is increasingly being paired with solar and wind generation.
“We are a mature industry,” Burwen said, slowing for emphasis.
It’s not all rosy, however. Burwen decried the Trump administration’s tariffs on storage technology imports.
“We have a global supply chain in the energy storage industry and certainly just as we are getting our legs underneath us, it is [an] incredible setback to have that uncertainty when folks are contracting years down the line,” he said. “So, that’s something that we’re trying to make sure that the administration is aware of — recognizing how much effort is going into promoting resilience and [how] storage can be key part of that.”
Storage remains dwarfed by wind (108 GW) and solar (75 GW) generation in installed capacity. And although ESA formed a political action committee last April, it raised less than $5,000 and disbursed only $2,000 in 2019. The American Wind Energy Association’s PAC disbursed more than $78,000 last year and more than $300,000 in the 2018 cycle. The Solar Energy Industries Association PAC spent almost $179,000 in the 2018 campaigns and more than $63,000 in 2019.
But there’s no doubt storage has gained some clout in D.C. As ESA was having its forum, CEO Kelly Speakes-Backman was testifying before a House Energy and Commerce subcommittee. She spoke in support of HR 4447, which would provide technical assistance to rural electric cooperatives for storage and microgrid projects, and HR 1744, a bipartisan bill that would amend the Public Utility Regulatory Policies Act to require utilities to consider storage in their supply-side resource planning processes.
Burwen said the industry “accelerated dramatically” last year. Congress saw the introduction of more than a dozen bills promoting storage, some calling for an investment tax credit. FERC conditionally approved RTOs’ compliance plans with Order 841, the commission’s 2018 rulemaking requiring the RTOs to allow energy storage resources full access to their markets. (See Storage Plans Clear FERC with Conditions.) New York and California expanded their storage incentives, with Nevada finalizing a storage target and Maine and Virginia recommending them. (Last week, Virginia lawmakers approved a 3,100-MW energy storage target by 2035.)
Battery storage costs have dropped dramatically, along with the cost of solar and wind generation, opening new opportunities.
“In the last two years, projects that pair renewables technologies with large-scale batteries have for the first time become economically viable,” BloombergNEF reported in its 2020 Sustainable Energy in America Factbook, released last week. “In particular, ‘PV-plus-storage’ projects have under-bid natural gas-fired plants to win power-delivery contracts in certain states thanks to a 77% drop in the price of a typical PV module and an 87% decline in battery pack prices.”
ESA says its “vision” is to reach 35 GW of storage by 2025, a 23-fold increase from current levels. “This is undoubtedly ambitious and will require fundamental changes in how the grid is planned and engineered, including a reform of U.S. energy markets and regulations,” ESA said.
It projects that electrifying transportation and buildings will add more than 3,500 TWh of annual demand in addition to current U.S. consumption of 4,200 TWh, with annual additions of storage reaching 7 GW in 2024. Wood Mackenzie Power & Renewables projects a more modest deployment of 4.4 GW in 2024.
To reach its goal, ESA is focusing its policy efforts on three goals: ensuring the ability to interconnect to the grid, which FERC supported with Order 845; including storage in all planning processes and procurements as an alternative to other resources; and winning compensation for the resource’s flexibility and other attributes.
The association has called for updating utility integrated resource planning to consider storage as an option for system capacity. IRPs, Burwen said, will be “the new RPS” (renewable portfolio standard). In the next five years, storage will become a “fully integrated part of” discussions on reaching 100% clean energy targets, Burwen said.
“In some respects, the last five years have been about mainstreaming energy storage as supply. And the next five years, we’re probably talking about mainstreaming energy storage as infrastructure, both in the grid and in the built environment,” he said.
RTOs Discuss Opening Doors for Storage
Panel discussions earlier in Wednesday’s conference included state regulators and officials from CAISO, MISO, PJM, ERCOT and NYISO.
Burwen asked one panel about RTOs’ role in resource adequacy, citing FERC’s controversial Dec. 19 order requiring an expansion of PJM’s minimum offer price rule (MOPR) to cover new state-subsidized resources. State officials have criticized the ruling as an attack on their jurisdiction over resource adequacy; some are considering withdrawing from the capacity market as a result. (See PJM MOPR Rehearing Requests Pour into FERC.)
Michael DeSocio, NYISO’s director of market design, said the issue is the subject of “conversations” in the ISO’s stakeholder processes and proceedings of the New York Public Service Commission.
“What we’re really looking for is a little bit of time. … These are complicated issues,” he said. “The markets have offered a level of transparency that you didn’t have before the markets existed, [which] is really important so you get a fair shake at making a go out of it. … I’d really hate to see that go away. So, we’re working hard to see if we can come up with solutions to those concerns.”
In a second RTO/ISO panel, ERCOT’s Kenneth Ragsdale said that although the Texas grid operator is not under FERC jurisdiction, Order 841 “helped us rationalize why we need to spend more time on storage.”
“We’re looking at how we can integrate [storage] with the system we have. … We’ve looked at allowing bid offer curves to be updated intra-hour instead of once at the hour. … We are trying to find the proper way to represent what this asset can provide to us [for resource adequacy]. We are really trying to get away from, ‘No you can’t interconnect that,’ to ‘Yes.’”
Stacey Crowley, CAISO’s vice president of external and customer affairs, said the ISO and storage providers are in the middle of a “trust-building exercise.”
“The operators are going to need to trust that those resources are there when the resource says they’re going to be there,” she said. “One of our really smart attorneys said, ‘Stacy. This is a marathon. And we are literally just tying our shoes right now.’”
Burwen noted that MISO generated controversy in December when it became the first RTO to file a proposal with FERC for treating storage as transmission.
The RTO’s storage-as-transmission-only assets (SATOA) proposal drew complaints that it would provide transmission owners a monopoly (ER20-588). The RTO said it was an initial step designed to avoid complexities over cost recovery, such as how non-TOs would be compensated for providing transmission services. SATOA resources would be barred from simultaneous participation in MISO’s energy market, at least initially. (See MISO SATOA Proposal Faces Opposition.)
Laura Rauch, MISO’s director of settlements, acknowledged the proposal is “imperfect.”
“If you read our filing, you saw that we acknowledge that this is … only a first step,” she said.
Glick Seeks Tech Conference on Hybrid Resources
In a keynote speech, FERC Commissioner Richard Glick acknowledged his two years on the commission have been “maybe a little more contentious than previous FERCs have been. We’ve had, certainly, quite vivid and interesting debates among the different commissioners and advisers.
“One of the reasons is that the transition to a clean energy future … creates a lot of conflicts,” he continued. “People that were in the business before that see their technologies are maybe on the way out are going to fight very hard. … There are winners and losers. Not everything is a win-win situation.”
“Chairman [Neil] Chatterjee has stated a number of times … he wants to make FERC boring again,” he continued, sparking laughter from the audience. “I have to say, he just hasn’t succeeded quite yet.”
But Glick credited Chatterjee for supporting Order 841 — one of the few times that the chairman voted differently than his fellow Republican, Commissioner Bernard McNamee.
He expressed hope that the commission will return to the issue of aggregated distributed energy resources, which it declined to act on in Order 841. “In my view, we should be ready to go. I don’t think there’s any additional information we need,” he said, noting the commission held a technical conference and received comments on the issue. (See Commenters Divided on DER Aggregation, State, LDC Roles.)
He also expressed confidence that the commission will prevail in a legal challenge over its jurisdiction over storage, noting the Federal Power Act gives it authority over all sales for resale, “even behind the meter.” State regulators, utilities and public power groups asked the D.C. Circuit Court of Appeals in July to overturn FERC’s decision not to allow states to opt out of Order 841. (See States, Public Power Challenge FERC Storage Rule.)
Glick said he wants to learn more about reports that storage providers have been reluctant to enter the energy markets in some regions, saying their involvement will be necessary to accommodate a big increase in intermittent renewables. “Especially if we don’t build as much transmission as we need to build, the only way to deal with this extra intermittency is through storage. A lot more storage.”
He also said FERC should hold a technical conference on hybrid storage. Among the questions the commission needs to answer, he said, is how the addition of storage to an existing solar or wind project affects its position in the interconnection queue and whether it is treated as a dispatchable or intermittent resource. “We need to learn what some of these issues are — what some of the barriers are — for hybrid technologies,” he said.
ERCOT said Friday it has approved the retirement of Public Service Company of Oklahoma’s coal-fired Oklaunion Power Station in the Texas Panhandle.
The Texas grid operator said staff have completed a reliability analysis and determined that the plant is not required to support transmission system reliability. The ruling clears the way for Oklaunion to be decommissioned and permanently retired as of Oct. 1.
Oklaunion Power Station | AEP
The 34-year-old, 650-MW plant’s ownership is split among utilities in both the ERCOT and SPP grids. AEP Texas owns a 54.69% interest in the plant. The other owners are the Brownsville Public Utilities Board (17.97%) in South Texas, PSO (15.62%) and the Oklahoma Municipal Power Authority (11.72%).
Below is a summary of the issues scheduled to be brought to a vote at the PJM Markets and Reliability Committee meeting on 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. (The Members Committee will also be meeting but has no voting items scheduled.)
RTO Insider will be in Valley Forge, Pa., covering the discussions and votes. See next Tuesday’s newsletter for a full report.
C. Manual 40: Training and Certification Requirements: Revisions resulting from cover-to-cover periodic review; includes updated temporary waiver language to allow more flexibility in addressing compliance with training and certification requirements.
1. Fuel Cost Policy (9:15-9:35)
The MRC will consider two different fuel-cost policy packages endorsed by the Market Implementation Committee in December. (See “Fuel-cost Policies,” PJM MIC Briefs: Dec. 11, 2019.)
The first package, compiled by a group of stakeholders, won 87% support and will be voted on as the main motion. The plan reduces penalties when a market seller self-identifies violations of its FCP and provides a “safe harbor” for force majeure scenarios and other situations of noncompliance that weren’t contemplated by the policy. The plan would also expand the use of temporary FCPs.
The PJM Industrial Customer Coalition and Calpine offered revisions to the first package that they said would address the RTO’s concerns about language applying penalties and duplicating benefits. The revisions clarify that the full penalty would be imposed if a unit is marginal in the day-ahead or real-time markets with a cost-based offer. A unit committed on its price-based schedule that later fails the three-pivotal-supplier test during its minimum run time or hours of its day-ahead commitment would also not incur the full impact factor unless the other conditions for market impact were met. About 81% of the committee endorsed this proposal.
Texas regulators last week approved a stipulated settlement of a CenterPoint Energy rate case that was a little more than 8% of the utility’s original request (49421).
The Public Utility Commission showed CenterPoint little love during its open meeting Friday, signing off on a $13 million settlement. The Houston utility had requested a $161 million recovery in April 2019, saying it had increased its customer base by 20%, installed 2.5 million smart meters and invested $6 billion in facilities since January 2010.
Left to right: Texas PUC Commissioners Shelly Botkin, Chair DeAnn Walker and Arthur D’Andrea discuss CenterPoint Energy’s rate case.
The agreement also reduces CenterPoint’s return on equity from 10% to 9.4%. It had asked for 10.4%.
CenterPoint filed the proposed settlement agreement in January. Parties included PUC staff; the Office of Public Utility Counsel; the city of Houston and other city coalitions; Texas Industrial Energy Consumers; Alliance for Retail Markets; Texas Energy Association for Marketers; and Texas Competitive Power Advocates.
The PUC also approved a rate-case-expense rider for Entergy Texas, allowing the utility to recover $6.4 million (48439).
The commission approved two settlement agreements resulting in $775,000 in administrative penalties:
EDF Energy Services was docked $475,000 for failing to reserve sufficient capacity to meet its responsive reserve service obligations (50304).
Oncor was penalized $300,000 over annual service quality (50350).
MISO last week released a set of draft future scenarios that would reflect in its transmission planning process the increasingly dominant role clean energy resources will likely play within the footprint as Midwest states push to decarbonize and electrify vital parts of their economies.
The RTO will use more aggressive renewable generation projections beginning with its 2021 transmission planning cycle (MTEP 21). Late last year, it released three draft 20-year futures — Announced Plans, Accelerated Fleet Change and Advanced Electrification — that take into account utilities’ decarbonization plans, the push toward renewable generation and increasing electrification in the footprint, respectively.
In December, some stakeholders questioned whether the proposed futures went far enough in terms of renewable projections. (See Stakeholders Debate MISO Planning Futures.)
At a special workshop Thursday, MISO revealed an updated strawman proposal, assigning the futures more neutral Roman numerals instead of titles.
Future I — formerly Announced Plans — assumes an 85% probability that companies’ renewable growth and carbon-cutting goals will materialize and full certainty that states’ clean energy plans will come to pass. It also includes a nearly 35% renewable generation penetration and a 40% reduction in carbon emissions from 2005 levels by 2040.
“This is hedging the possibility that some of these plans are vague and may not come to fruition,” MISO Planning Manager Tony Hunziker said.
Future II — previously Accelerated Fleet Change — assumes MISO members meet or exceed decarbonization plans while carbon emissions drop 60% from 2005 levels. Electric vehicle adoption stimulates demand, while residential and commercial electrification reaches 39% of its technical potential.
Future III — Advanced Electrification — also assumes members fulfill their renewable plans and consumers adopt EVs. It foresees a sharp increase in demand because of electrification and residential and commercial electrification hitting 77% of its technical potential. MISO also experiences a minimum 50% renewable penetration level as carbon emissions dip 80% below 2005 levels.
MISO said the proposed MTEP 21 futures show “significant evolution” from those of MTEP 19, where renewable penetration topped out at about 36% of the resource mix by 2035 in the most aggressive future.
The RTO wants to have the new futures finalized by July.
Carbon emission modeling assumptions by future | MISO
Hunziker said MISO’s Board of Directors is “very interested” in moving ahead on the futures redesign in light of the RTO’s rapidly changing resource mix and recently filed integrated resource plans at state commissions.
“It’s still very much a draft,” Hunziker told stakeholders. “We’re pouring the concrete, but it hasn’t set yet, so we can still form it, push it around before it is set in stone.”
The futures will go before the Planning Advisory Committee at its March 11 meeting, where stakeholders will have another opportunity to suggest alterations.
‘Choking Point’
Some stakeholders asked how flexible the concrete will be when dried, asking if MISO was leaving room in its planning scenarios to include even more fleet transition. They said the RTO seems to be at an inflection point of utilities and states announcing stepped-up carbon-cutting measures.
Hunziker said MISO is introducing a survey tool as part of the futures’ analysis to continue to solicit companies’ announced plans along with state mandates and goals.
He also said the RTO is partnering with the Organization of MISO States to get commissions’ most up-to-date decisions on their utilities’ resource additions and retirements. The idea is to get a single repository of commissions’ decisions instead of MISO “minding the vast, expansive infowebs,” he said.
Mississippi Public Service Commission consultant Nick Puga asked if MISO has vetted the futures’ electrification predictions with outside consultants.
Hunziker said MISO’s electrification projections are based on internal research and data from outside consultants, including Applied Energy Group.
“If the Super Bowl ads were any indication, it looks like there will be a lot of electric vehicles … potentially in the next year,” Hunziker said.
Multiple stakeholders asked MISO to schedule a special workshop with stakeholders to describe the RTO’s approach to its electrification projections. Hunziker said MISO will consider the request.
Veriquest Group’s David Harlan asked that MISO provide stakeholders with each future’s projected subregional energy mix, capacity supply broken down by fuel type and load shapes. He argued that if the futures are intended to drive transmission investment decisions, members should have a better idea of which generation sources will be matched up with load on the subregional level.
Minnesota Public Utilities Commission staff member Hwikwon Ham reminded stakeholders that MISO is planning for new transmission, not trying to pinpoint exact locations of future generation.
“We don’t need to project where resources will be precisely available,” Ham said, adding that the system has recently become a “choking point” in getting new resources built and interconnected.
NEW ORLEANS — Could this be the year SPP and MISO finally agree on an interregional transmission project?
Maybe. At least that’s what staff responsible for planning at the RTOs’ seam implied last week during a panel discussion at the Gulf Coast Power Association’s 7th annual MISO South Conference on Feb. 11.
An optimistic Casey Cathey, SPP’s manager of transmission planning and seams, assured a questioner that the grid operators will produce a coordinated system plan (CSP) this year. Two previous attempts have failed to yield an interregional project the organizations could agree on.
“We’re in heavy coordination and very close to coming up with some projects,” Cathey said. “For the first time in I don’t know how many years, we’ve got a good shot of getting a project through [the CSP].”
SPP’s desire for interregional projects has been driven by a wish to relieve congestion in eastern Kansas, which borders the MISO footprint. The growing impetus for MISO is the north-south transfer constraint between its Midwest and South regions.
As a result of a 2015 settlement agreement between the RTOs that also involves other parties, MISO is limited to 1,000 MW of contracted, firm transmission capacity between the two regions through SPP’s system, but it also has access to additional non-firm service capped at 3,000 MW in southbound flows and 2,500 MW northbound. (See SPP, MISO Reach Deal to End Transmission Dispute.)
Under the agreement, MISO pays SPP between $16 million and $38 million in base annual payments based on an annual available system capacity-usage factor. In February, that arrangement became subject to a 2 to 4% escalation rate. The limits also created problems during energy emergency alerts (EEAs) in 2018 and 2019, when MISO said the constraint prevented it from accessing resources to relieve the emergency.
With the agreement set to expire in February 2021, MISO is motivated to bring “operational certainty” to its members through new transmission projects or by purchasing additional firm capacity. (See MISO Floats New Option for Midwest-South Constraint.)
“One of our objectives is to get to the point of long-term regional certainty,” said Jeremiah Doner, director of seams coordination for MISO.
“There will be another EEA event, with possible load shed,” Cooperative Energy COO Nathan Brown warned. “We really need some focus there.”
SPP could also be looking at its first international interregional project, Cathey said. The RTO shares a direct tie with Canada’s SaskPower through Basin Electric Power Cooperative’s existing transmission facilities in North Dakota and completed its first international transaction in 2015 when it imported power during an emergency situation. (See SPP, SaskPower Make First International Trade.)
A provision in SPP’s joint operating agreement with SaskPower allows joint planning analysis and coordinated system planning. With the oil-rich province of Saskatchewan facing continued load growth, SaskPower and SPP have held preliminary discussions.
“[SaskPower] can help fund projects in SPP and therefore improve their import capability,” Cathey said. “There are just so many things going on.”
Electric Industry Outpacing Others in Cybersecurity
SPP Director Mark Crisson opened a special briefing workshop GCPA held on the RTO by noting the growing importance of cybersecurity in the electric industry.
“Twelve years ago, this wasn’t on anyone’s radar,” he said. He recalled that when he became CEO of the American Public Power Association in 2007, he would receive “private, confidential” briefings from the Department of Homeland Security on industry cyber threats that were not to be shared with anyone else.
“It’s much more of an industry dialogue with the government now,” he said. “The nature of these threats evolve all the time. It’s hard to stay ahead of the bad guys, but it’s critical for our industry. We are way ahead of what other industries are doing, both with the steps we’re taking, the information we’re getting from the government, and the teamwork between us and the government.”
Crisson said SPP has developed its own set of cybersecurity criteria “that allows [us] to evaluate how effective or robust our cybersecurity really is.”
SPP currently scores itself above average, or between three and four on a five-point scale, Crisson said.
“We feel like we’re making good progress, but there’s a lot more to do here.”
Uncertainty Product a Key for SPP Reliability
The workshop mostly focused on the SPP Holistic Integrated Tariff Team’s work to integrate the growth of renewable energy, boost reliability, and improve transmission planning and the wholesale market. (See SPP Board Approves HITT’s Recommendations.)
Bill Grant, regional vice president of regulatory and strategic planning for Xcel Energy’s Southwestern Public Service, joined a panel of SPP members in explaining the HITT’s recommendation to develop an uncertainty product as “the art of dispatching.”
“We can handle the system a little differently if we have certainty,” said Grant, a former control center manager. “We have to develop tools for operators so they can react when there are any questions about the [generation] forecast.”
The HITT listed the uncertainty product as an “other reliability service,” which include new technologies that change the “underlying nature of grid operations that are not traditional operator tools.”
Grant pointed out that SPP’s market protocols and rules limit the flexibility dispatchers have to work with. However, the flexibility, or uncertainty product, is also needed as variable renewable generation takes a larger share of the fuel mix.
“Developing the uncertainty model will help us better learn about the market,” said Nebraska Public Power District’s Tom Kent, who chaired the HITT.
MISO saved members between $3.2 billion and $4 billion over the course of 2019, the RTO said last week.
The savings could be attributed to “enhanced reliability, more efficient use of the region’s existing assets and a reduced need for new assets,” MISO said in its annual Value Proposition study, which compares benefits of RTO membership against going it alone on the grid.
The estimated value to members was partially offset by $296 million in MISO administrative costs.
The savings are nearly identical to 2018, when MISO estimated it delivered between $3.2 billion and $3.9 billion in benefits to members. (See MISO Claims up to $3.9B in 2018 Benefits.) The RTO said it has documented nearly $27 billion in member benefits since 2009.
MISO executives discussed the most recent customer savings estimates during a special conference call Friday.
“Value Proposition on Valentine’s Day. Nothing could be more appropriate,” Executive Director of Market Operations Shawn McFarlane had joked at the Market Subcommittee meeting Feb. 6.
Breakdown of 2019 Value Proposition study | MISO
MISO said the lion’s share of last year’s value — $3.1 billion — could be chalked up to a diminished need for more grid assets. Those savings were further broken down to $415 million to $477 million from MISO’s wind generation integration, $154 million to $261 million from its demand response program and $2.2 billion to $2.7 billion from its vast geographic footprint.
Improved reliability accounted for a $405 million in savings, while a more efficient use of the footprint’s existing assets accounted for another $374 million, consisting of savings from more efficient dispatch ($283 million to $313 million), regulation reserves ($49 million to $54 million) and spinning reserves ($23 million to $25 million).
“The benefit of our large footprint is peaks occur at different times,” said Leonard Ashley, MISO senior business adviser of strategy and business development, adding that hot weather doesn’t often occur simultaneously in Indiana and the Dakotas, allowing the RTO to more easily distribute supply.
NERC has finished transitioning to the latest version of its situational awareness tool and plans to introduce it to reliability coordinators once the vendor developing the system has implemented new modeling software, the vendor’s CEO told the ERO’s Operating Reliability Subcommittee on Feb. 11.
Additional features being added to the tool include separate views for RCs, FERC and the ERO Enterprise, along with advanced data visualization tools incorporating a range of information such as substation performance, space weather, gas pipeline availability and fire tracking.
“We’re building a process that will allow you, the RCs, at very little manual work other than review, to continue to push updated model information into SAFNR v.3,” Legatt said. “Therefore, the impact to the RCs will be lower, and the accuracy of the tool will go up significantly.”
SAFNR v.3 went live for NERC and the ERO Enterprise in December 2019. Darrell Moore of NERC said that the tool will be rolled out to remaining stakeholders after ResilientGrid finishes building models with updated information from the RCs.
Clarity Sought on IROL Exceedance Metric
The task force revising the metric for identification of interconnection reliability operating limits (IROLs) brought two recommendations to the subcommittee for feedback: to ensure consistency in reporting by requiring operators to report all IROL exceedances with no operating margin added, and to change the threshold for reporting from 10 seconds to one minute.
“As the ORS is kind of our [forum] to talk to subject matter experts, we want your feedback on the proposed changes — should we start taking the steps to make this modification so that we can have a better, more valuable metric?” asked Maggie Peacock, manager of advanced analytics at SERC Reliability and chair of NERC’s Performance Analysis Subcommittee.
Several members of the subcommittee urged the task force to address what they saw as a lack of clarity in the recommendations. In particular, John Norden, director of operations at ISO-NE, said the metric should be clear as to whether it includes any buffer an operator has built into its system.
“It probably should be consistent, because the last thing we want to do is give doubt to an operator,” Norden said. “[If] you have a 1,000-MW transfer limit as your limit, and the operator gets to 28 minutes and he’s at 1,050, should he take action to get below 1,000 in the [last] two minutes, or should he say I have a buffer? … The limit’s the limit, as far as I’m concerned, and that’s what you should operate to, whatever you put in front of the operator.”
Members Object to RCIS 2021 Development
The group developing the successor to the Reliability Coordinator Information System (RCIS) is currently working on a request for proposals. It hopes to choose a vendor by the second quarter and introduce the tool by early next year.
Creation of the new software, called RCIS 2021, is being conducted by the Eastern Interconnect Data Sharing Network (EIDSN), a group created in 2014 to further develop industry tools that NERC has decided it no longer wants to maintain. NERC initiated the project in 2017 to replace the current RCIS with a more modern architecture and provide a common platform for instant communication between RCs, as well as between RCs, NERC, and transmission owners and operators.
Some at the meeting raised strong concerns about a perceived lack of input from Western operators into the system, as EIDSN is composed of representatives from the Eastern and Quebec interconnections. These were amplified when EIDSN Executive Director Jim Schinski said that use of RCIS 2021, which is required by several NERC standards, will be subject to a fee paid to EIDSN.
“Speaking for my company, and I think for others, we’re going to have some strong objections to that,” said Tim Beach, director of reliability coordination at RC West. “Because you’re [requiring] us to participate … and pay, with no control over requirements or cost in the future.
“I understand the tool needs to be replaced. Full agreement with that. … But the process of getting there and the requirement to use it seems a little upside-down to us in the West,” he added. [Editor’s Note: A previous version of this article mistakenly attributed this quote to Tim Reynolds, manager of event analysis and situation awareness for the Western Electricity Coordinating Council.]
Richard Mandes of EIDSN told members that “they’re paying for that functionality today through NERC” and that the fee paid to EIDSN would cover the same services they are getting now. He also promised that members would have an opportunity to provide input into the design of the system through NERC before it is introduced.
