The Public Utility Commission (PUC) of Texas on Monday approved the choice of John Paul Urban as its executive director during a special open meeting.
PUC Chair DeAnn Walker said Urban will oversee “something of a reorganization” once he comes on board.
Urban brings a strong political background with him. He worked in a number of legislative positions since graduating from the University of Texas in 2000 and was the PUC’s director of government relations for three and a half years before joining NRG Energy in a managerial position.
PUC OF Texas commissioners left to right: Brandy Marquez, DeAnn Walker and Arthur D’Andrea meet on personnel matters. | AdminMonitor
“Based on his past tenure at the PUC, John Paul has an excellent grasp of the agency’s mission and a sterling reputation in both the capitol and our regulated industries,” Walker said in a statement. “We are confident in his ability to lead the agency as it fulfills its oversight role.”
Walker also announced new titles for two long-time staffers as part of the strategic alignment that Urban’s hiring will complete. Thomas Gleeson, who has been at the commission for 10 years, will become the PUC’s chief operating officer, while Stephen Journeay will become commission counselor in the Office of Policy and Docket Management.
Journeay, who sits in front of the PUC during open meetings and coordinates the work on dockets, will now report directly to the commissioners, instead of the executive director. He is a licensed attorney and professional engineer and has been with the PUC since 1996.
“When I found out he was reporting to the executive director, it didn’t make much sense,” Walker said. “He really reports to us.”
Walker also announced Andrew Barlow has been hired as the PUC’s communications director. Barlow previously served in communications roles for former Texas Gov. Rick Perry and former Texas Lt. Gov. David Dewhurst.
MISO is moving ahead with a proposal to largely recycle last year’s 15-year transmission planning predictions for use in its 2019 Transmission Expansion Plan, but some stakeholders are urging the RTO to at least expand the plan.
During a March 20 workshop to gather stakeholder input on MTEP 19, MISO Planning Manager Tony Hunziker said the futures were developed for reuse over multiple planning cycles, with small updates to cover uncertainties such as the capital cost of building generation, demand growth rate and projected fuel prices. (See MISO: Minimal Change to 2019 Tx Planning Futures.) Stakeholders generally support the idea, he said.
MISO last year created four future scenarios for use in MTEP planning, including:
A limited fleet change future, in which the fleet remains relatively static with coal units retiring at the end of their useful life;
A continued fleet change scenario, in which the grid develops according to the trends of the past decade;
An accelerated fleet change future driven by a strong economy that increases demand and motivates carbon regulations and increased renewable use; and
A future in which distributed and emerging technologies become more widely used.
MISO planners are proposing small adjustments to some MTEP 19 assumptions, namely to account for sluggish load and higher-than-expected renewable penetration.
With energy growth currently outpacing load growth, planners say MISO should abandon its previous practice of assuming energy will grow at 0.5 to 1.5 times the base growth rate (extrapolated from load-serving entities’ current forecasts) in its transmission planning, and instead plan for anything from no growth to twice the base growth rate. Preliminary demand forecasts from LSEs show a 0.3% average growth rate through 2027, down from 0.5% in MTEP 18 and 0.6% in MTEP 19, while energy is expected to grow at a 0.5% rate.
MISO staff are also considering raising projected renewable penetration by 5% across all futures — from 10-30% to 15-35% of capacity. They acknowledged that the low end of the MTEP 18 range does not reflect the number of renewables on track to complete the interconnection queue.
| MISO
The RTO also plans to update its base futures model to include planned units holding a certificate of public convenience and necessity, as well as units that have a signed generator interconnection agreement.
MISO will take stakeholder input on MTEP 19 futures through April 20 and expects to have futures finalized by September.
Fifth Future
But some stakeholders are asking MISO to create of a fifth future. Investment firm Veriquest requested the RTO develop an additional scenario that focuses on the regional siting of distributed resources, while MISO’s Environmental sector asked for a standalone future showing how possible federal or state carbon regulations drive fleet evolution.
Veriquest’s David Harlan said he’d like to see futures more informed by future capacity needs.
“I still don’t have a good picture where the source of needs is and where the capacity is,” Harlan said. He urged MISO planners to make projections to share with stakeholders about who benefits from cost-effective transmission requirements to move wind from North Dakota to Mississippi, for example.
“None of that is visible in this process,” Harlan said.
MISO Director of Policy Studies J.T. Smith said the RTO does account for future capacity movement when building MTEP models.
The Transmission Owners sector said the potential industry changes depicted in the four MTEP futures adequately capture future impacts to the transmission system. “While some of the currently defined futures, such as the limited fleet change, may not align well with the current industry projections, those futures provide valuable information … as well as provide a counter to the more aggressive generation change assumptions implemented in other futures,” it said.
Apex Clean Energy’s Richard Seide asked if MISO is accounting for commitments from utilities that intend to eliminate the use of coal, such as Consumers Energy, which recently announced its plans to go coal-free by 2040. (See CMS Energy Plans a Zero-Coal Future by 2040.)
“I don’t know how to say it, but the world has changed … and it occurred very quickly. You’re sitting on the largest queue ever,” Seide said.
Shane O’Brien, of MISO’s resource forecasting group, said stakeholders have so far said the RTO’s retirement projections are adequate. The RTO does not hold utilities to retirement announcements or include them in planning until owners submit Attachment Y retirement notices.
BOSTON — The numerous East Coast offshore wind projects being developed through individual state procurements should be viewed as regional resources, panelists told a New England energy conference last week.
The 10 GW of offshore wind slated for the region has already reached a critical mass that has lowered financing costs and promises local suppliers a real market rather than a one-off opportunity, a panel of three offshore developers and one state regulator said during the Raab Associates’ 157th New England Electricity Restructuring Roundtable on Friday.
Massachusetts in 2016 set a goal to develop 1,600 MW of offshore wind by 2030, followed last year by New York, which is targeting 2,400 MW by 2030. New Jersey this year topped both with a target of 3,500 MW by the same year.
While slightly behind Massachusetts, New York is in a hurry to get rolling and plans to issue its first 400-MW offshore wind solicitation this fall, followed by a similar one in 2019, said Alicia Barton, head of the New York State Energy Research and Development Authority. (See NY Offshore Wind Plan Faces Tx Challenge.)
“I think people are looking at this the wrong way, looking at it state by state,” Barton said. “These are all leases in federal waters and this will be a growing Northeast regional resource rather than a state-by-state resource.
Although New York’s Public Service Commission will make the final determination, NYSERDA would propose to provide eligibility to projects that can either deliver directly into NYISO or through an adjacent control area, she said.
“We are eager to send the message that all of these leaseholders should be looking at this New York market opportunity and this procurement coming up,” Barton said.
First Actor Advantage
Representatives of the three developers who bid into Massachusetts’ offshore wind solicitation in December supported Barton’s regional resource theme, but each would first like to win the Massachusetts contract.
Orsted North America President Thomas Brostrom said his company will soon announce the first offshore wind factory in the U.S., to be located in Massachusetts. He said Orsted has “entered into an exclusive arrangement with a very large and recognized European manufacturing company” for the facility.
For the solicitation, Orsted partnered with Eversource Energy to form Bay State Wind, which proposed a 400-MW or 800-MW wind farm 25 miles off New Bedford, to be paired with a 55-MW battery storage facility.
“You create an industry when you have volume and pipeline,” Brostrom said. “You have basically a pipeline of 10 GW; that’s why we think we can create a local supply chain now.”
The growing reality of a Northeast offshore wind industry is already influencing bankers, who have quickly reduced the cost of project financing, he said.
In its initial request for proposals in its 83C solicitation last July, Massachusetts sought a minimum of 400 MW of offshore wind but said it would consider bids of up to 800 MW if it determines that a larger proposal “is both superior to other proposals submitted in response to this RFP and is likely to produce significantly more economic net benefits to ratepayers.”
| Deepwater Wind
The three developers, Bay State, Deepwater Wind and Vineyard Wind (the last of which is a joint venture between Avangrid Renewables and Copenhagen Infrastructure Partners), placed their bids in December and the state will announce winners on April 23, with contracts to be submitted at the end of July. (See Mass. Receives Three OSW Proposals, Including Storage, Tx.)
Brostrom presented Orsted as the global leader in offshore wind, but Matthew Morrissey, vice president of Deepwater, said his company was the leader in the Americas, having built the 30-MW Block Island project, the only offshore wind farm operating in the U.S.
Deepwater also signed a contract with the Long Island Power Authority last year for the 90-MW South Fork project, scheduled to become operational in 2022.
In Massachusetts, Deepwater proposed two versions of Revolution Wind, a 200-MW wind farm consisting of about 25 turbines, or one double that size.
“Revolution Wind contains a very innovative, expandable transmission system, a pumped storage offering and, for a project of this scale, enormous economic impact,” Morrissey said. “The Brattle Group provided us with a study — 2,700 jobs, $300 million in economic impact, and we are committed to delivering our power in 2023.”
Deepwater’s proposal includes an agreement with the largest hydroelectric pumped storage facility in New England, the 1,200-MW Northfield Mountain station operated by FirstLight Power Resources.
“The reason why timing matters here — Alicia said it’s a regional industry and I fully agree with that — but the reality is that the first projects will decide where the first part of the supply chain goes,” said Lars Pedersen, CEO of Vineyard Wind, which submitted proposals for 400-MW and 800-MW wind farms with approximately 50 and 100 turbines, respectively. “And if you follow the logic from Europe, the more of a head start you get, the more likely you are to get more of the supply chain.”
There will be supply chain up and down the East Coast, as there should be, Pedersen said, but Massachusetts has an “incredible” starting advantage with the harbor in New Bedford. He said that synergies on the transmission side of the project would enable his company to build an 800-MW line for essentially the same cost as a 400-MW one.
There’s more to transmission planning cost containment than simply comparing estimates among proposals, stakeholders learned last week at a special session of the PJM Planning Committee on the issue.
While all sides presented differing opinions, they also seemed to strike a conciliatory tone.
Staff highlighted procedural and process challenges of adding cost containment as a factor in decisions, including the potential impact the extra analysis would have on the timing of developing planning models. They also explained that project costs often must be considered as a range, rather than a specific number, which complicates comparisons.
LS Power’s Sharon Segner walked through the final two of four templates her company has proposed to help PJM standardize its comparison of transmission proposals based on several factors, including transparency, the strength of the cost-containment proposal and developers’ rate requirements. Her cost-cap analysis, for example, would create a checklist of attributes, and proposals would be categorized based on how many of those attributes PJM believed each one had.
“If it’s a weak cost cap, it’s essentially treated as a cost estimate,” Segner explained, noting that estimates would calculated based on the in-service year rather than at the time of the proposal.
“We want a better understanding about how PJM values cost containment. … From my company’s standpoint, we think there needs to be improvement [in the PJM comparative cost analysis] from the status quo,” she said. “There’s been a lot of good points raised by the transmission owners in saying … these projects have to meet the technical need and they have to solve the technical problem. … That is my company’s position as well.”
A series of events at January’s Markets and Reliability Committee meeting culminated in the issue going back to the Planning Committee for additional consideration and LS retaining control of the main proposal that the MRC will consider. To ensure its proposal has enough support to be implemented, LS narrowed the focus of revenue requirement caps to include just total all-in return on equity and capital structure cap proposals and removed the ability to offer caps on operations and maintenance costs. A representative for NextEra Energy supported removing the operations and maintenance cost-cap option. The proposal goes back before the MRC at its May meeting. (See “Transmission Flashpoint,” PJM Markets and Reliability Committee Briefs: Jan. 25, 2018.)
Transource Energy’s Brian Weber made a presentation that endorsed some of the LS goals but also opposed the overall proposal. He said it would put the focus on cost containment and “severely limit” what developers offer, moving PJM away from the “creative solutions” of the sponsorship model for transmission planning and toward the procurement model used in other RTOs/ISOs.
PJM’s sponsorship model is similar to that used for architecture proposals, where bidders are encouraged to develop their own creative solution to necessary criteria and staff are prepared to consider a wide range of potential factors. The procurement model is more like the bidding process for construction contractors, where the design has already been chosen and applicants are mostly competing on cost. A hybrid approach that tries to focus on both creativity and cost could limit the ability to achieve either of them.
RTO staff underscored the implication in their analysis of the changes necessary to consider cost-containment factors.
“Almost everyone else in the industry has one bucket of risks,” PJM’s Mark Sims said. “It adds a dimension to the level of analysis that PJM has to do.”
“I think the pragmatic reality of this is that developers will limit their submissions” due to their project designs being subsequently awarded to undercutting competitors, Weber said, adding that the plan “provides pretty significant disincentive to provide value” through creativity.
Erik Heinle with the D.C. Office of the People’s Counsel praised the technical creativity and asked why it couldn’t be replicated on the financial side.
“Great technical flexibility should be matched with flexibility and creativity in the cost arena as well,” he said.
“There is a difference between creativity and blind risk taking,” Weber responded. “Which risks should developers be expected to take? They should be expected to take the risks that they can control.”
Earlier in the meeting, PSEG Services’ Vilna Gaston had said she hoped that incorporating those cost-focused measures wouldn’t lead to a situation like the fatal bridge collapse in Florida on March 15. Ruth Ann Price with Delaware’s Division of the Public Advocate agreed and noted that media coverage showed the bridge contractor had several past successes along with several safety complaints.
Weber touched on this concern in his response to Heinle, noting that he has seen developers take risks in their cost-capped agreements filed at FERC and that he is confident they could not have had the time to perform the due diligence necessary to ensure they’re doing it correctly.
Building Consensus
Alex Stern with Public Service Electric and Gas presented transmission owners’ analysis of how easily the current proposals could implement design components that were previously identified. The analysis found that PJM’s original proposal could implement the principles with relative ease; however, it was vetoed at the MRC meeting in January.
Stern said he “fully respect[s]” concerns about gold-plating the system but acknowledged that “PSE&G would probably be at a competitive disadvantage because we’re not going to lower our standards for the customers of our state and anything we’re involved in … to the minimums that were set in [the Designated Entity Design Standards Task Force]. We’ll try to abide by what we believe are the right standards.”
He said a reasonable alternative would be limiting cost caps to construction costs.
“We’re not supportive of cost caps. Having said that, as part of the negotiation and consensus building, we were willing to try to consider taking that step. … I don’t like it, but I would concede … that it’s probably the one that provides bang for the buck to the ratepayer with an ability to track and achieve objectives. It’s probably the most enforceable,” Stern said, suggesting that implementing cost containment is such a big change that it should be eased into slowly.
“The sponsorship model might not be the best model for complex cost caps and there are challenges. I’m not suggesting it’s not doable; I’m suggesting there’s more challenges with it,” he said. “And that begs the question, do we change up the paradigm to facilitate broad-based cost caps recognizing there’ll be impacts to [the Reliability Pricing Model], they’ll be impacts to the [Regional Transmission Expansion Plan], there’ll be impacts to the interconnection queue … or do we start smaller and see how things work first?”
Heinle and Price urged implementing some way to standardize comparisons so their offices have a better chance to engage in the process. Price said staff in her office who don’t fully understand the process will immediately decline expensive projects, “so I need information to convince them.”
“If we compare apples to apples to apples, it becomes a lot easier,” she said. “I think most offices want to be actively involved in projects in their regions, but they need to the tools to be reasonably [informed].”
PJM’s Steve Herling said the process is already completely optimized and there is no lag time available for additional analysis on understanding and comparing values.
“There comes a time where there’s nothing left you can do. … You’ve got a fixed start time and a fixed end time and everything you add has to fit in between” to finish the annual RPM case build, he said. “We don’t believe you can fit it in the time frame you have. There is more work required than can be fit into this schedule.”
He pointed out that it might not be possible to standardize the process to show whether costs are comparative costs.
“There are going to be times when something is a little more than you need and there’s going to be times when it’s a lot more than you need. People make proposals. Our job is to figure out whether it’s a little more than we need or a lot more than we need and then figure out is the additional cost worth it,” he said.
The New York Public Service Commission on Thursday ruled that upstate municipal power authorities can charge higher electricity rates to cryptocurrency companies in order to prevent disproportionate increases in local retail rates.
The intense computer processing by cryptocurrency companies, such as Bitcoin miners, requires large amounts of electricity, prompting them to move their server farms upstate for the relatively cheap hydropower.
The order (18-E-0126) cited the situation in Plattsburgh, where monthly bills for average residential customers increased nearly $10 in January because of two cryptocurrency companies operating there.
The New York Municipal Power Agency, an association of 36 municipal power authorities in the state, petitioned the commission regarding concerns that these high-density load customers were having a negative impact on local power supplies.
Cryptocurrency companies look for commercial or industrial facilities where they can access the large amounts of power required for their banks of computers to create — or “mine” — digital currency.
The commission “must ensure business customers pay an appropriate price for the electricity they use,” said PSC Chair John B. Rhodes. “This is especially true in small communities with finite amounts of low-cost power available.”
In some cases, such currency miners account for 33% of a municipal utility’s total load, an “extraordinary amount” of power for a single customer to use, the commission said. By comparison, a large paper manufacturer employing hundreds of workers might use one-quarter the amount of electricity per square foot of such customers.
PSC Slashes National Grid Electric Rate Increase
The PSC approved three-year electric and gas rate plans for National Grid that came up far short of the company’s requests.
The ruling (17-G-0239) limits electricity revenue increases in the first year to only $43 million (1.7%), rather than the $326 million (13%) sought by the utility. Natural gas revenue increases in the first year were capped at $13 million (2.4%), compared to the requested $81 million (14%).
A typical residential customer using 600 kWh of electricity per month under the new rate plan would see a total monthly bill increase of $2.22 (2.9%) in the first year starting in April 2018, $3.03 (3.8%) in the second year and $3.25 (3.9%) in the third year. Eligible low-income electric customers will see a bill reduction of up to 55%.
The plan “includes a nation-leading affordability policy that substantially lowers bills for most low-income customers,” Rhodes said. “It moves forward the state’s climate agenda by expanding energy efficiency while funding non-wire alternatives and other REV-like initiatives for smarter investments.”
PSC Continues Crackdown on ESCOs
The commission ruled to restrict three energy service companies (ESCOs) from serving low-income customers while granting a fourth company its petition to serve them after demonstrating that it could guarantee a 1% savings against the utility price.
The March 15 actions (17-G-0239) included suspending the ability of Flanders Energy to market to and enroll new residential and nonresidential customers and directing the company to refund any overcharges to customers that it enrolled without proper authorization. Flanders does business in Consolidated Edison’s service territory.
The commission also denied separate petitions from Drift Marketplace and M&R Energy Resources for rehearing on original orders denying the companies’ requests to serve low-income customers. Neither company was able to demonstrate how it was going to guarantee savings, the rulings said. Drift does business in Con Ed’s territory, while M&R operates in the Central Hudson Gas & Electric and Orange & Rockland Utilities areas.
“Our ongoing efforts to reform the ESCO market remains a priority,” Rhodes said. “In instances where an ESCO proves they are fair to customers, we allow them to continue their activities in New York to bring choice and energy services to customers.” (See NYPSC Limits ESCO Service, Sets New DER Compensation.)
The commission approved New Wave Energy’s petition, which stated the company will immediately assign all its customers that participate in the utility assistance program to its guaranteed savings product. New Wave operates in the National Grid, New York State Electric and Gas, National Fuel Gas and Rochester Gas & Electric service territories.
The state’s Department of Public Service has provided evidence that many ESCOs have been significantly overcharging many mass market customers. It has also found many ESCOs have abused customers via high-pressure and deceptive sales tactics, teaser contracts and exploiting vulnerable elderly, immigrant and low-income populations.
PSC Approves Tier 2 Changes to CES
The PSC expanded Tier 2 of the state’s Clean Energy Standard, changing Maintenance Tier eligibility to include certain renewable facilities in operation prior to Jan. 1, 2015, and establishing delivery requirements into New York consistent with those for Tier 1.
The order (15-E-0302) applies only to eligible, pre-existing renewable facilities and expands the number of projects eligible for funding under the program in cases of need. The commission also increased the size threshold for eligible existing hydropower facilities from 5 MW to 10 MW, and provided for a streamlined review process, as well as a standard contract term of three years with the potential for contract renewals.
The commission said the changes will reduce the administrative burden on facilities seeking maintenance support and will better reward the environmental contributions of existing baseline renewable resources.
PSC Hems on Public Policy Tx Planning
The commission on Friday declined to identify and refer any public policy transmission planning requirements to NYISO.
The March 16 order (16-E-0558) directed DPS staff to work with the ISO and the New York Transmission Owners to identify potential transmission constraints on the bulk and non-bulk systems that may warrant the future identification of a public policy requirement, considering current and projected resources.
| NYSEG
The commission said that while it “recognizes that there are certain regions, such as the northern and southwestern parts of the state, where additional transmission facilities may support the deployment of renewable resources, the extent and magnitude of such needs requires further consideration.”
NYISO’s Tariff, approved by FERC, says that the PSC may identify which public policies, if any, constitute requirements; if the commission identifies such a need, the ISO will then solicit and evaluate proposed solutions to it.
ISO-NE’s draft 10-year Capacity, Energy, Loads and Transmission (CELT) forecast is reducing projected summer loads in 2026 by nearly 6% in part because of a sharp increase in projected energy efficiency, RTO officials told the Planning Advisory Committee on Thursday.
The draft 2018 CELT reduces the net annual energy forecast by 4.5% lower in 2025 with the net summer 2026 50/50 forecast reduced by 6.0% and the summer 90/10 forecast cut by 5.8%.
The behind-the-meter solar photovoltaic forecast for 2026 is about 0.6% higher, with energy efficiency boosted by 16.2%. The new report foresees about the same regional economic growth through 2026 as last year’s forecast.
The gross 50/50 load forecast — calculated before reductions from passive demand resources (PDR) and behind-the-meter PV — was cut by 2.7%, and the gross 90/10 forecast was 2.8% lower. The gross annual energy consumption forecast increased by 0.3%.
ISO-NE’s draft 2018 CELT report increases the gross annual energy consumption forecast by 0.3% over the 2017 study. | ISO-NE
The solar PV forecast included the expected impact of the tariffs imposed on solar panels by the Trump administration. It also includes a 0.5%/year PV degradation rate to account for solar panels’ declining conversion efficiency over time, based on research by the National Renewable Energy Laboratory.
The RTO develops the CELT 10-year forecast as part of its annual forecast process.
The finalized forecasts will be shared at the April 26 PAC and published by May 1.
Update on Transmission Projects
ISO-NE has put 22 upgrades in service since October, the RTO said in its transmission projects and asset condition update, including the new Scobie–Tewksbury 345-kV line and five other projects in the Boston area.
The RTO reported an $11.9 million increase in the estimate cost for Project 945–Adams in Central Western Massachusetts (installing two new 115-kV breakers and replace two existing 115-kV breakers and associated line relocations). The cost increased because of “an enhanced understanding of the multiple site condition impacts on the construction plan,” the RTO said.
That increase was more than offset by a $12.3 million reduction in the estimated cost of Pittsfield/Greenfield Projects 1662, 1664, 1665 and 1663 because of “project cost alignments.”
No new reliability or market efficiency-based transmission system upgrades have been added to the Regional System Plan project list since October. However, 36 new projects totaling $549.5 million have been added to the Asset Condition list, largely for the replacement of aging infrastructure.
Eastern Connecticut 2027 Needs Assessment
The PAC heard an update on the 2027 Eastern Connecticut (ECT) Needs Assessment, which is evaluating reliability needs for the 10-year period extending until 2027.
The draft needs analysis found violations of low-voltage and high-voltage reliability criteria for first and second contingencies as well as some severe thermal violations in some areas following second contingencies. All the violations were also found to be present in 2020.
ISO-NE announced the needs analysis last June. The previous ECT 2022 Needs Assessment report was finalized in June 2015 but work on solutions to address the region’s time-sensitive needs were suspended in February 2017 pending a review of RTO criteria, assumptions and methodologies impacting needs assessments and solutions studies.
The RTO said the review had “sufficiently progressed” to allow initiation of the new study.
The final scope of work was posted earlier this month, along with responses to stakeholder comments.
The study area is a rectangle bounded by the Long Island Sound on the south and the Massachusetts border on the north, with the eastern boundary the Rhode Island border and the western boundary just west of New London.
| ISO-NE
“This area hasn’t been studied in a long, long time,” said Brian Forshaw, a consultant for Connecticut Municipal Electric Energy Cooperative (CMEEC). “So, we’re glad to see things are progressing from a needs assessment to solutions studies.”
He said, however, that the needs assessment was “more limited than it should have been” and criticized the “top-down” load forecast.
The finalized needs assessment will be posted by May 31. The RTO will work with Eversource Energy and CMEEC to address the needs on their transmission systems.
Eversource Equipment Replacements
Eversource made a presentation on the replacement of its Montville 16X 115/69-kV transformer, which is at its end of life after 67 years. Total project cost is estimated at $6.3 million (-25%/+50%).
The company also provided an update on replacement of the Card Street 11F-5X autotransformer, which was originally presented in September.
The September PAC presentation recommended its replacement with a three-phase spare unit located at the Montville 4J Substation. Eversource said it conducted a re-evaluation that determined the summer long-term emergency rating of the replacement could be increased from 458 MVA to 512 MVA. The existing autotransformer is rated at 491 MVA. The estimated cost remains $8.6 million (+50%/-25%).
Transmission Planning Technical Guide
ISO-NE is continuing its revisions to the Transmission Planning Technical Guide, which was reorganized last year to a new format with four main sections: Introduction, Modeling Assumptions, Reliability Criteria and Guidelines, and Analysis Methodology.
Revision 2 was posted on the ISO website on Nov. 14, 2017.
Staff is now updating the appendices for consistency with the RTO’s style guide and publication template:
App. A – Terms and Definitions (Expected Q2 2018): Adding/removing terms and definitions; adding references to NERC and Northeast Power Coordinating Council glossary of terms.
App. B – Fast Start Generation List: Retired after change to probabilistic methods for base case dispatches of transmission needs assessments and solution studies.
App. C – DR Modeling Guide (Expected Q2 2018): New terminology associated with price responsive demand (PRD).
App. D – Damping Criteria: Retired after criteria moved to Section 3.3.3 of Technical Guide.
App. E – Voltage Sag Guideline (Expected Q2 2018): Update to clarify methodology.
App. F – 2000 STF Memo (Draft Posted March 2018): Updated diagrams for clarity.
App. G – Phase Shifter Guide (Draft Posted March 2018): Changed name from Modeling Guide to Phase Shifter Guide to focus on content of appendix; remove Sackett Phase Shifter and 3rd Waltham Phase Shifter; update all descriptions to match current operating practices.
App. H – No-Fault Contingencies (Draft Posted March 2018): Updated to current version of Planning Procedure No. 3.
App. I – Transfer Methodology (Draft Posted March 2018): Reorganized structure to align with Technical Guide format; new terminology associated with PRD.
App. J – Load Modeling Guide (Draft Posted March 2018): Added descriptions for solar PV modeling; added equations to explain methodologies; new terminology associated with PRD; adding Area-Owner-Zone-Bus assignments.
Stakeholders can provide comments for 15 days after the posting of each document on the PAC website to PACMatters@iso-ne.com. Comments on Appendices F, G and H are due April 3.
The PAC’s next meeting is April 26 at the Doubletree Hotel in Milford, Mass.
BOSTON — FERC Commissioner Robert Powelson said last week that New England needs to overcome its aversion to new energy infrastructure to avoid natural gas shortages in the winter.
“You all burned 2 million barrels of oil during this recent bomb cyclone,” Powelson said at Raab Associates’ 157th New England Electricity Restructuring Roundtable on Friday. “We didn’t do that in Pennsylvania; we burned a lot of natural gas, we ran economic nuclear plants and we integrated renewables with close to 1,400 MW of wind capacity.” (See Van Welie: ISO-NE in ‘Race’ to Replace Retirements.)
Paired in a session with ISO-NE CEO Gordon van Welie, Powelson was the only FERC commissioner who voted against accepting the RTO’s Competitive Auctions with Sponsored Resources (CASPR), the grid operator’s two-stage capacity auction to accommodate state renewable energy procurements.
Powelson wrote a dissent calling the construct “a complicated, patchwork solution that will neither accommodate the desires of the states, nor send proper price signals to market participants.” (See Split FERC Approves ISO-NE CASPR Plan.)
“Here you are today, with 15 million customers in the New England market during these weather events paying some of the highest gas [and electricity] costs in the country,” Powelson said. “My good friend here [van Welie] will say, ‘Well that was the least-cost resource.’ Well so much for your [greenhouse gas] requirements that you’ve set forth as state regulators.”
Powelson did say he was “extremely impressed” with the RTO’s capacity auction results last month, where the clearing prices were the second-lowest in the history of the market. (See ISO-NE Capacity Prices Hit 5-Year Low.)
Despite his praise of some aspects of the New England wholesale electricity market, Powelson joked, “Gordon, I might have you come down to PJM, do a little 12-step program.”
Extreme weather events put regulators on a “tipping point” of addressing reliability, Powelson said.
“We’re seeing this tectonic shift in our baseload resources of accelerated retirements of coal and nuclear plants,” he said. “Last time I checked, we’re not building coal plants in New England — is that correct? By the way, I live in Pennsylvania, and we’re not building a lot of coal plants in Pennsylvania; in fact, I don’t think we’re building any.
“I looked at the last two capacity auctions; the clearing resource is a combined cycle gas plant with a 6,600 heat rate, sourced under the greatest blessing we have — and I don’t want any boos in this room, but Marcellus shale has had a profound impact on my state’s economy,” he said.
Powelson continued a theme he had taken up earlier in the week at the American Council on Renewable Energy’s (ACORE) Renewable Energy Policy Forum in D.C., where he said that ISO-NE’s Operational Fuel Security Analysis report issued in January was “like a horror story.” The study found the region will face energy shortfalls because of inadequate natural gas supplies in almost every fuel-mix scenario by winter 2024/2025. (See Report: Fuel Security Key Risk for New England Grid.)
“Siting is hard, but you gotta get there,” he told the ACORE conference Wednesday, citing the region’s inability to win approvals for new gas pipelines or transmission to import Canadian hydro.
“Fifteen million customers in [New England] paid the highest gas-basis costs in the country and they were less than 200 miles from the Leidy gas hub in Pennsylvania in a $2.34/MMBtu trading market,” he continued. “I recognize it’s probably going to be hard to get 30-inch pipe into New England, but in lieu of that, we’ve got to solve this problem. … This is all going to be a failed experiment if we have reliability issues in the New England states.”
Massachusetts Sierra Club Director and Newton City Councilor Emily Norton challenged Powelson at the Boston conference, saying she was “surprised and disturbed” at his “lack of attention to the full costs” inherent in choosing fracked gas, such as the water pollution in Pennsylvania.
“To that customer or to your constituent, I think they should have peace of mind that they’re going to have safe, affordable and sustainable energy to their homes,” Powelson said. “A lot of people in Pennsylvania are switching fuel from oil to natural gas. Not everybody can afford a rooftop solar installation on their house, or a battery storage behind that, or for that matter, a propane or natural gas-fueled Generac or Cummings generator.”
ISO-NE’s 2025 lookout has some alarming points for a regulator, he said. He added that he had read about the risk of rolling blackouts and other emergency measures becoming necessary in New England if the region didn’t act to secure the supply of natural gas for its generators.
“Look, what happens with Millstone?” Powelson said. “I don’t know, I’ll leave that to Connecticut, [PURA Vice Chairman Jack] Betkoski and others, and Gov. [Dannel] Malloy. What happens more recently in this post-bomb cyclone with lack of adequate gas supply where you’re dealing with storage issues here in the New England market? There’s a case where storage is meeting your demand right now, but we don’t have adequate pipelines into the market.
“The reality for this region is that state governors, both Democrat and Republican, are committed to incent investment and develop policies that support that investment, which is a good thing,” Powelson said. “In lieu of a national energy policy, the states have to drive that. … The states are getting ahead of the federal government. So be it. … But we’re also building a lot of things in the PJM footprint.”
Resilience of the Grid
Closing on the topic of resilience, Powelson said that he and his fellow FERC commissioners “are in a very good spot.”
“The feedback from the RTOs has been what we expected,” he said. “If a resource needs to close and exit the market, there should be orderly entry and exit, and I use my example of PJM, where roughly 13,000 MW have come offline. That’s the reality of the market.”
Price suppression created by resources like cheap natural gas is displacing uneconomical resources, “so why should we go out there and pick winners and losers in a market?” Powelson said. “To do what? Hurt the other, more efficient units in the market or send bad market signals?”
Van Welie said the question is how much further the RTO can go with retirements before they must slow them down.
The National Oceanic and Atmospheric Administration last fall “forecast a return to ‘normal’ winter after two unseasonably warm ones, whatever ‘normal’ is in New England anymore,” van Welie said. “But no one was predicting a 100-year cold snap over the Christmas-New Year break.”
The RTO’s winter preparedness program created an incentive for the oil-burning generators to fill up going into the winter, but when it came to resupplying during the winter, they were buying on the spot market, van Welie said. (See ISO-NE Plans for Hybrid Grid, Flat Loads, More Gas.)
“And they were competing with home heating on the spot market,” van Welie said. “So then we hit all kinds of logistics problems, where truck drivers don’t have enough hours to move the fuel around, and the oil suppliers are going to supply homes before they’re going to supply generators.”
The RTO’s job is “to procure the reliability services we need through the wholesale market construct,” he said. “In our resiliency filing with FERC, we are asking for a year to work things out, asking to wait until the second quarter of 2019.”
Moderator Jonathan Raab asked van Welie: “If CASPR is a transition mechanism, what might be a long-term solution to help states ‘achieve’ their climate reduction commitments without undermining the integrity of wholesale markets?”
“The obvious answer is carbon pricing, but we’re not going to do that as none of the states want to,” van Welie said. “It’s really going to have to be the states that take the lead on that.”
— Rich Heidorn Jr. reported from the ACORE conference in D.C.
The D.C. Circuit Court of Appeals on Friday upheld FERC’s determination that NorthWestern Energy’s proposal to recover the costs of a generating station providing regulation service was not just and reasonable.
The court rejected NorthWestern’s claim that FERC’s decision was “arbitrary and capricious” and violated the Administrative Procedure Act’s requirement that an agency’s decision be “reasonable and reasonably explained” (No. 16-117).
The Midwest utility had filed with FERC to revise its rates to recover the costs for its Dave Gates Generating Station, a gas-fired facility built in Montana to provide its own regulation service, after purchasing 60 MW annually of the service from other utilities became too expensive. The 150-MW plant went into service in 2011.
Dave Gates Generating Station | Corval Group
NorthWestern proposed to use Gates to supply 105 MW of regulation service to all its customers. Retail customers would pay for 45 MW at a state-approved rate, separate from Schedule 3 under NorthWestern’s Tariff with FERC. Retail and wholesale customers would pay for the remaining 60 MW under Schedule 3, which was calculated by multiplying the plant’s revenue requirement by 0.57 (the ratio of 60/105).
The utility also proposed to charge customers for fuel costs but credit them for any revenue the Gates plant might bring in from off-system sales and other nonregulation service sales; charge customers for the regulation service that it purchased during a 2012 outage; and charge customers for any regulation service that NorthWestern might need to purchase during future outages.
FERC affirmed an administrative law judge’s order reducing NorthWestern’s proposed rate by: (1) multiplying the revenue requirement by a different cost-calculation ratio of 0.13 (19/150); (2) excluding fuel costs from the Schedule 3 rate and rejecting the utility’s crediting arrangement; (3) requiring the utility to make a separate filing to recover costs associated with the 2012 outage; and (4) requiring it to make separate filings before charging customers for any regulation service that it might need to purchase during future outages.
The commission directed NorthWestern to refund its customers the difference between the proposed rate and the modified rate. It also denied a request for rehearing.
Northwestern Energy Generating Facilities | Northwestern Energy
NorthWestern raised four challenges in arguing the case before the D.C. Circuit in December. It said FERC “unreasonably” reduced the numerator of its proposed cost-calculation ratio from 60 MW to 19 MW, but the court said the commission “reasonably modified” the calculation after determining that only 19 MW were needed to serve Schedule 3 customers.
The utility also contended that the commission arbitrarily increased the denominator of its proposed calculation from 105 MW to 150 MW. The court disagreed, noting that under FERC precedent, the denominator should reflect the nameplate capacity (150 MW), not just the megawatts that NorthWestern planned to devote to regulation service.
Third, NorthWestern argued that FERC inadequately explained its decision not to allow fuel costs and failed to account for the fact that the utility may be able to retroactively recover fuel costs. The court ruled otherwise.
Finally, the utility said the commission acted arbitrarily by requiring it to make separate Section 205 filings to recover costs associated with the 2012 outage and for any regulation service that it might need to purchase during future outages. FERC adopted the ALJ’s reasoning, which justified the separate proceedings on reasonable grounds, and “acted reasonably here as well,” the court ruled.
Writing for the court, Judge Brett Kavanaugh said he was not persuaded by NorthWestern’s challenge of FERC’s order for refunds. He noted that the commission “concluded that NorthWestern over-collected from its Schedule 3 customers, making this the kind of case in which FERC ordinarily orders refunds.”
The February Fortnightly features an article about the German Energiewende (“Energy Transition”) that makes three basic claims: (1) Germany is successfully decarbonizing with renewables, (2) Energiewende is “good news for consumers” and (3) there will be no adverse impact on electric reliability.[1]
The first two claims are simply wrong. The third cannot be correct.
Wrong: German Electricity is Decarbonizing
German electricity isn’t decarbonizing. Because of its tragic decision to close nuclear plants, Germany is substituting coal and renewables for nuclear.
Despite the increase in renewable generation that Fortnightly extols, there has been no material decrease in carbon dioxide emissions from German electric generation. Germany is doing much worse than the European Union generally, much worse than the U.S. and much worse than France, as shown by changes in electric sector carbon dioxide emissions (2008 baseline):[2]
| Eurostat, EIA
In a nutshell, Germany is substituting coal and renewables for nuclear,[3] while the U.S. and France are substituting natural gas and renewables for coal.[4] Germany isn’t making a serious dent in its carbon dioxide emissions from electricity, while other nations are.
Does Germany “point the way”? No way.
Wrong: Energiewende is Good News for Consumers
Truth is that Energiewende has driven Germany’s sky-high electricity prices even higher. Here are Germany’s residential prices relative to the European Union, France and the U.S. (U.S. cents/kWh):[5]
| Eurostat, EIA
It may be hard for Americans to get their heads around it, but German residential electric prices are now three times U.S. prices.
For U.S. regulators out there, how many years of a 10% price increase each year would it take for the average U.S. residential price to reach the average German residential price?
The answer is 12 years. But the torches and pitchforks appear long before then. Like Year 2.
By the way, Energiewende hasn’t yet hit stride. Germany is planning much more costly renewable and transmission projects that are estimated to ultimately cost 25,000 euros per family household.[6] That’s $30,750 American.
Does Germany “point the way”? No way.
Cannot be Right: No Impact on Reliability
The Fortnightly article claims that decarbonization has/will have no adverse impact on reliability. This claim is premature and cannot be correct.
The vision seems to be that Germany gets rid of all nuclear plants and all coal plants, and will rely on a combination of renewable resources, flexible fossil (presumably natural gas) generation, demand response and storage (batteries).
Fortnightly seems to think this is feasible because “Germany already produces hours of nearly 100% renewable electricity on the system.” According a German spokeswoman, “‘Baseload is no longer needed,’ otherwise it could ‘block the grid.’”
Say what? The problem isn’t hours when solar and wind generate enough to meet demand. The problem is all those other hours when they don’t, like these sorts of hours and days and weeks:[7]
| Eurostat, EIA
Renewables generated very little for a two week period. The vast bulk of demand had to be met with existing conventional power plants.
Supposed Reliability Fixes
Now let’s look at the supposed fixes when existing nuclear and coal power plants are eliminated: flexible fossil fuel (natural gas) generation? Creating a new fleet of gas generators with the necessary pipeline infrastructure would be astronomically expensive and make Germany even more dependent on Vladimir Putin’s natural gas.
By the way, the new German coalition agreement’s sole reference to natural gas is: “Make Germany a location for liquefied natural gas (LNG) infrastructure.”[8] No such LNG infrastructure exists, and the one proposed LNG terminal looks like more of a pipe dream.[9] And a very expensive one at that.
OK, how about demand response? An optimistic estimate of theoretically possible DR is about 10% of Germany’s total demand,[10] requiring a new infrastructure and, of course, customers’ agreement.
Not only is the potential small, but the demand reduction is for one or two hours max. The chart above shows solar and wind can take a powder for days on end.
Batteries fall prey to this same problem. The cost of batteries is typically quoted in terms of four hours of stored energy for each hour of maximum output. What if you need battery output to last eight hours? Then the nominal cost of batteries doubles. If you need 24 hours, then the nominal cost of batteries goes up six times.
So when we think about the need to cover days of renewable non-generation, we should understand that the cost of batteries is many times the current publicized cost. And we can understand why no sophisticated industry player is flocking to batteries (unless subsidized by Other People’s Money — in which case they’re a great idea of course).
The claim that Germany can maintain reliability without nuclear and with only “very small amounts of fossil fuels,” as the article says, sounds like it came from the breatharians, who believe they only need air, and not food, to survive. We don’t hear from them too often — at least not the same ones. For the obvious reason.
The Fortnightly article goes on to cite customer outage and loss-of-load expectation (LOLE) data and projections supposedly demonstrating continued reliability under Energiewende. But the vast bulk of customer outages are attributable to distribution and transmission problems, not resource problems (as the article itself notes at the outset citing a Rhodium Group report). So outage data, especially with renewables still a minority of total resources, says nothing about future resource adequacy.
As for LOLE projections, the article relies on studies that assume that more than 30 GW of coal plants remain in Germany[11] — which is the opposite of the article’s premise that they are eliminated. You can’t eat your cake and have it too.
In summary, Germany’s future without nuclear and without coal has no plausible means of meeting customer demand.
Does Germany “point the way”? No way.
Bottom Line
Energiewelde isn’t decarbonizing German electricity, only increasing sky-high electric prices, which it will continue to do indefinitely. And reliability can’t be sustained on the equivalent of thin air.
Energiewende does point a way. The wrong way.
Steve Huntoon is a former president of the Energy Bar Association, with 30 years of experience advising and representing energy companies and institutions. He received a B.A. in economics and a J.D. from the University of Virginia. He is the principal in Energy Counsel, LLP, www.energy-counsel.com.
FERC last week denied a complaint by SPP transmission owners that the RTO’s transmission zonal placement is unjust and unreasonable, saying the members did not meet their burden of proof to back up their claims (EL18-20).
The companies filed their complaint in October, arguing that a “loophole” in SPP’s Tariff forces customers within an existing zone to pay a share of the legacy costs for transmission lines newly integrated into the zone. That practice, the complainants said, runs counter to the “no legacy cost shift” protections SPP has established to prevent cost shifting between zones. (See SPP Tx Owners Take Zonal Placement Concerns to FERC.)
The TOs contended SPP’s zonal integration decisions create unjustified rate increases in the form of cost shifts between customers. They argued the Tariff is unduly discriminatory because the cost shift burden is not evenly distributed and the disparate rate treatment is not based on any differences in service or the customers.
The legacy TOs said SPP’s recent creation or expansion of multi-owner zones highlighted various notice and equity issues that did not exist in historical single-owner zones.
Kansas City Power & Light made the filing and was joined by American Electric Power (on behalf of subsidiaries Public Service Company of Oklahoma and Southwestern Electric Power Co.); City Utilities of Springfield, Mo.; KCP&L Greater Missouri Operations; Nebraska Public Power District; Oklahoma Gas & Electric; Omaha Public Power District; Southwestern Public Service; Sunflower Electric Power; Mid-Kansas Electric; Westar Energy; and Western Farmers Electric Cooperative.
The companies filed after failing to revise the Tariff to include a mechanism holding customers in an existing zone harmless from network integration transmission service rate increases of more than 2% or $1 million (whichever is lower). The proposal was rejected by both the Markets and Operations Policy Committee and the Board of Directors in July. (See SPP Board Rejects Changes to Tx Zonal-Placement Rules.)
The commission said that although it was denying their complaint, “this does not alter the rights that existing SPP transmission owners … have to represent their interests and take action to address cost shifts that may result from zonal integration.”
Pointing to SPP’s newly revised TO zonal placement process that sets notice and information-exchange requirements for potential new TOs, the commission said existing owners retain their ability to negotiate with the RTO and new owners about zonal integration issues and to design measures to mitigate potential cost shifts. (See “SPC Approves Zonal Placement Process Document,” SPP Strategic Planning Committee Briefs: July 13, 2017.)
In addition, parties can participate in SPP’s stakeholder process to develop and consider proposals to address this issue with more comprehensive participation by all stakeholders, FERC said.
SPP argued that not every cost shift resulting from placing a new TO in an existing zone is unjust and unreasonable. It said FERC has never taken a “rigid view” that rate impacts and cost shifts are universally and patently unjust and unreasonable, but instead “recognizes that matters of rate design involve judgment on a myriad of facts.”
The RTO asserted that its Tariff is not unjust and unreasonable because it does not require SPP to involve itself in evaluating and mitigating cost shifts. Those determinations are best addressed by the commission on a case-by-case basis, SPP said.
Proposed Tariff Revisions Set for Settlement
The commission set for settlement hearing SPP’s proposed Tariff revisions to add an annual transmission revenue requirement (ATRR) and implement a formula rate template for transmission service using South Central MCN’s facilities, when the utility acquires them and transfers their functional control to the RTO.
In an order related to the hearing, FERC also approved South Central’s purchase of transmission lines and related assets from the city of Nixa, Mo.
FERC said its preliminary analysis indicates that SPP’s proposed Tariff revisions “may be unjust, unreasonable, unduly discriminatory or preferential, or otherwise unlawful,” but it accepted and suspended them to become effective the first day of the month after South Central acquires the Nixa assets, subject to refund and the outcome of other ongoing proceedings before the commission.
The commission granted SPP’s waiver request of its regulations regarding cost-of-service statements, consistent with its prior approval of formula rates. However, it allowed the administrative law judge to provide for “appropriate discovery of such information.”
SPP filed its request in October, proposing to incorporate South Central’s previously accepted formula rate to populate the utility’s ATRR with certain Nixa transmission facilities. SPP said the assets, about 10 miles of 69-kV lines and associated infrastructure, interconnect with its system in the Southwestern Power Administration (SPA) and City Utilities of Springfield pricing zones, but are not included in SPP rates.
The RTO proposed placing the Nixa assets and their associated ATRR in the SPA zone, using the revised zonal placement process. The Nixa assets would be the first facilities subject to the revised process.
FERC noted that South Central’s formula rates and implementation protocols are the subject of several ongoing proceedings before the commission, and that the utility has also filed a request for rehearing or clarification.
“Accordingly, certain provisions of South Central’s previously approved formula rate template and implementation protocols could change based on the outcome of those proceedings,” FERC said.
AEP, KCP&L, Sunflower, Mid-Kansas, Westar and Xcel Energy took issue with SPP’s rate-impact analysis under the new process.
The TOs argued that SPP’s calculation of a 46% rate increase “appears to be a simple comparison of total zonal ATRR before and after South Central’s integration.” They said that because network service rates are based on ATRR and load ratio share, it would be necessary to evaluate the ATRR and any associated changes in load to accurately determine the rate impact.
The TOs also contended that the rate impact on existing customers in the SPA zone “is further obfuscated” by the fact that Nixa’s load transitioned to SPP network service in June 2017, but the transfer of facilities and recovery of their ATRR through zonal rates would not occur until a later date.
SPP argued that it did not fail to calculate the impact of adding load because South Central is not a load-serving entity and the Nixa load had already begun service in the zone. That meant there was no change in load associated with the assets’ integration, the RTO said.
Responding to a complaint that it “did not provide sufficient evidence” of the assets’ actual rate impact in the SPA zone, SPP said it provided the information “directly to each SPP transmission customer” in the zone during the zonal-placement process.
South Central, a transmission-only SPP member, said it intends to transfer functional control of the facilities to the RTO once the transaction closes. The facilities will be incorporated into the utility’s ATRR in its zone.
FERC found the transaction to be in the public interest because:
It does not involve the transfer of generation facilities or the combination of transmission facilities with affiliated generation in the same market, and thus would not have an adverse effect on competition;
It would not have an adverse effect on rates, as potential rate increases in the SPA zone would be attributable to incorporating the Nixa facilities, not the change in ownership; and
It would not have an adverse effect on regulation. The commission said it found no evidence that either state or federal regulation will be impaired by the transaction, and noted that no party alleges that regulation would be impaired by the transaction and no state commission has requested that FERC address the effect on state regulation.
South Central said the ATRR for transmission service using the Nixa facilities will be recovered pursuant to its formula rate from SPP ratepayers in the zone. Nixa currently recovers its costs to own and operate the assets directly from retail customers through a bundled rate that includes its costs for generation, transmission and distribution service.
The utility acknowledged that “there will be a ‘rate impact’ in the broadest sense” because of the new arrangement but said that the zone’s customers will see only “very small” increases in their rates, pointing to an estimated annual difference of $87,000 between its ATRR and Nixa’s ownership. It said those increases will be offset by the transaction’s benefits.
South Central is a subsidiary of GridLiance, a competitive transmission company that collaborates with public power utilities. The Nixa municipality serves more than 9,000 retail customers.
