American Electric Power said last week it will focus on smaller projects after Texas regulators put the kibosh on the company’s proposed $4.5 billion Wind Catcher project.
“We’re looking at obviously smaller segments, smaller wind farms with smaller transmission, multiple areas,” CEO Nick Akins told financial analysts during the company’s third-quarter earnings call on Oct. 25. “That’s one of the lessons learned.”
PSO’s gas-fired Tulsa Power Station provides resource adequacy | Public Service Co. of Oklahoma
AEP canceled the massive project — which would have included a 2-GW wind farm in the Oklahoma Panhandle and a 360-mile, 765-kV transmission line — the day after the Texas Public Utility Commission rejected its application in July. (See AEP Cancels Wind Catcher Following Texas Rejection.)
Akins promised analysts they would see resource plans developed around renewables, storage and natural gas. The Columbus, Ohio-based company said in February that it wanted to reduce carbon dioxide emissions from 2000 levels by 80% by 2050.
“It will be smaller capacity segments focused on various jurisdictions, and we’ve already started that process,” Akins said.
AEP reported third-quarter earnings of $578 million ($1.17/share), compared to $545 million ($1.11/share) a year ago.
The company increased and narrowed its 2018 operating earnings guidance to $3.88 to $3.98/share, from $3.75 to $3.95/share. Akins said AEP’s projected growth rate of 5 to 7% annually was not “predicated on Wind Catcher” and it remains unchanged.
On a tumultuous week that saw the S&P 500 index lose the remainder of its 2018 gains, AEP shares finished at $72.74/share, a drop of $2.81 (3.7%) from its Oct. 24 close before reporting earnings.
Xcel Energy Just Missed Expectations
Minneapolis-based Xcel Energy announced on Oct. 25 third-quarter earnings of $491 million ($0.96/share) compared with $492 million ($0.97/share) for the same period in 2017.
Xcel Energy Wind Farm | RTO Insider
Xcel just missed analysts’ expectations, as recorded by Zacks Investment Research, of 98 cents/share. The company said higher operations and maintenance expenses partially offset favorable weather conditions and sales growth.
CEO Ben Fowke told analysts that Colorado regulators’ approval of its Colorado Energy Plan provides a “model for how the clean energy transition can occur in the United States.” Under the plan, Xcel’s Colorado subsidiary plans to retire 660 MW of coal generation, replacing it with 1,100 MW of wind power, 700 MW of solar and 275 MW of battery storage.
Share prices were down 3.5% ($1.75/share) in the two days following the earnings announcement, closing at $48.51 on Oct. 26.
NextEra Earnings Up from 2017
NextEra Energy reported third-quarter earnings on Oct. 23 of $1.01 billion or $2.10/share, up from $847 million and $1.79 during 2017’s third quarter.
NextEra CEO Jim Robo said in a statement that the company’s Energy Resources development team expanded its backlog of renewable projects by a record 1.41 GW. NextEra added 850 MW of wind, 447 MW of solar and 120 MW of battery storage projects and expects to have 10 to 16.5 GW of renewable power projects within the 2017-2020 time frame.
The Florida-based company’s stock lost 1.6% of its value following the earnings announcement, ending the week down $2.77/share at $169.89.
AUSTIN, Texas — ERCOT market participants shared their thoughts with the Texas Public Utility Commission last week on how to address the energy-only market’s lack of scarcity pricing and slim reserve margins.
Power companies and advocacy groups made their pitches during an Oct. 25 PUC technical workshop reviewing the market’s 2018 performance during a summer with an 11% reserve margin (Project 48551). Despite the tight margins and 14 system demand peaks bettering the 2016 record, the ERCOT market handled the summer heat without resorting to emergency actions.
Some participants suggested a shift in the loss-of-load probability (LOLP) used to calculate real-time reserves in ERCOT’s operating reserve demand curve (ORDC). Others suggested tweaking the ancillary services market. Still others said the market works just fine, thank you: No changes are necessary.
A common concern was that without higher prices and scarcity pricing this summer, the forward demand curve did not signal a need for additional generation.
“We view this discussion … as whether the current level of risk the signals in the energy-only market construct are delivering are considered acceptable,” said Michele Gregg, executive director of the Texas Competitive Power Advocates (TCPA), which represents generators, power marketers and retail providers. “The simple fact is that the lack of scarcity pricing only worsened the backward-dating forward curves, making future investment in dispatchable generation even more difficult.”
The TCPA recommends shifting the LOLP by up to one standard deviation, a position shared by Exelon.
“We believe the current scarcity pricing will not improve resource adequacy,” said Bill Berg, Exelon’s vice president of wholesale market development. “As we look ahead the next three or four years, it’s obvious to us the fleet is changing. A shift of one should shore up the existing fleet, support the renewable development we think is coming and leave enough new money in the market to incent new generation. We think 1.0 will keep you at a level where you can hold on for a few years.”
“We’re not afraid of high prices, when they are justified,” said Thompson & Knight attorney Katie Coleman, speaking for the Texas Industrial Energy Consumers trade association. “ERCOT is the only truly competitive market in the world, and we are proud of that. We think the market performed well this summer. We think you can expect that kind of performance to continue, because that is what the market is designed to do.”
“There’s no perfect answer here,” NRG Energy’s Bill Barnes said. “What we have is a competitive market. When there is scarcity, the prices should reflect a reliability risk. That did not match up this summer.”
Steve Reedy, the ERCOT Independent Market Monitor’s assistant director, noted several market participants had said similar generator outage rates shouldn’t be expected again in the future.
“I’ll point out that with the lower outage rates, we had a more secure, less risky system this summer, and that fed into the lower prices,” Reedy said. “Should we have the same events repeat next summer, but with our normal outage rate, we will see high prices, and we probably wouldn’t be talking about the need to change the LOLP.”
The PUC is moving quickly to address the feedback, with staff pulling together information from the workshop and written comments for a discussion by the commissioners as early as November.
PUC Chair DeAnn Walker said she wants to get an earlier start planning for the 2019 summer with ERCOT staff, market participants and other governmental agencies than she did last year. She plans to once again coordinate generator and transmission outages and ensure maintenance work is completed by May.
Walker is also scheduling time with Christi Craddick, chair of the Texas Railroad Commission, which regulates gas pipelines, to ensure the lines are operating. The two also worked together before this summer to handle pipeline outages, “but we were working on one contract, one pipeline at a time,” Walker said.
“I agree … that 2019 is going to be hard. There’s no steel in the ground coming, and everyone wants to move to Texas, but that’s a great thing. We keep getting more and more load,” Walker said. “I also believe our system and the whole dynamics of the market are changing. It’s going to be difficult down the road, and we need to think on that.”
Avangrid earnings jumped more than 25% year-over-year in the third quarter, mainly driven by increased gross margins for renewables and new transmission rate plans.
The company posted net income of $125 million for the quarter ($0.40/share) versus $95 million ($0.32/share) a year earlier. For the first nine months of 2018, net income was $476 million ($1.54/share) against $458 million ($1.48/share) in the first three quarters of 2017.
During an analyst call Wednesday, the company also said it foresees solid future growth based on its role in developing the largest offshore wind project in the country. (See Mass., R.I. Pick 1,200 MW in Offshore Wind Bids.)
Avangrid’s 800-MW Vineyard Wind offshore project signed 20-year contracts with the Massachusetts Department of Public Utilities in August.
Offshore wind | Avangrid
CEO James P. Torgerson said during the call that subsidiary Central Maine Power had obtained FERC approval for transmission service agreements for its New England Clean Energy Connect (NECEC) ahead of schedule. The project would bring up to 1,200 MW of Canadian hydropower to Massachusetts.
“Both Vineyard Wind and NECEC are on track, and we expect all permits and final approvals in 2019,” he said.
Torgerson said Maine regulators were close to granting NECEC a certificate of public convenience and necessity, but the state’s Public Utilities Commission on Friday said they would suspend hearings related to the project. (See related story, Maine PUC Move Poses Hurdle for NECEC.)
Significant Opportunities
The Vineyard project, a 50/50 partnership with Copenhagen Infrastructure Partners, calls for development in two phases. The first 400 MW will be operational at the end of 2021 for $74/MWh, with annual escalations of 2.5%, while the second phase, slated for a 2022 operations date, has a price of $65/MWh, again with 2.5% annual increases over 20 years.
Torgerson said both phases are eligible for investment tax credits and capacity payments. The company is looking at “significant additional opportunities for offshore wind” in Massachusetts, New York, Rhode Island and farther south, he said. Avangrid has a lease on 122,000 acres 24 miles offshore Kitty Hawk, N.C., enough for 2.4 GW of wind, and has secured a position in PJM’s queue to interconnect three planned 800-MW projects near Virginia Beach, Va. The development process “is moving a little quicker now” because of Virginia’s plans to solicit up to 2 GW of offshore wind by 2028, Torgerson said.
Avangrid also expects to bring 970 MW of onshore wind and solar into operation by the end of 2019 and estimates 2.7 GW of renewables development through 2022.
Regulatory Update
Transmission rate base ($M), currently capped at 11.74% | Avangrid
Torgerson also took note of FERC’s Oct. 16 ruling changing how it sets return on equity rates for transmission owners. (See FERC Changing ROE Rules; Higher Rates Likely.) The commission set a base ROE for Avangrid and other New England Transmission Owners of 10.41%. “The new ROE cap including incentives … would go up to 13.8%,” Torgerson said. “If this goes ahead as laid out by the commission, we would see a slight benefit to the higher ROE cap versus the lower ROE base. … So, 64% of CMP’s and [United Illuminating’s] transmission is currently capped at the 11.74%, and we get a benefit by going above that.”
The Maine PUC also recently found that CMP acted reasonably in preparing for and responding to the major storm that occurred in October 2017, and at the same time ordered the utility to file a rate case by Oct. 15.
“We asked for a $24 million rate increase; however, there won’t be any rate impact to customers as we use some of the tax reform liabilities and file that back to customers, so they won’t see a rate increase; yet we will get the ability to earn another $24 million in revenue at least,” Torgerson said.
GEORGETOWN, Texas — The Texas Renewable Energy Industries Alliance’s (TREIA) 2018 GridNEXT Conference attracted a devoted group of renewable energy developers and marketers to a three-day discussion of how renewable technologies in Texas are transforming the “grid of the future.” Attendees participated in panel discussions on building sustainability with renewables, planning for a resilient system and recoverability, and building community engagement.
TREIA board of directors member Ingmar Sterzing, a partner in renewable project developer Skaia Energy, moderated a leadoff panel that looked at the organization’s vision of reaching 50% renewable energy in Texas by 2030. He said the state, which already leads the nation with more than 18% of renewable-generated electricity, can produce enough power from additional wind (15.5 GW), solar (43.3 GW) and storage (550 MW) resources to reach that 50% figure.
ERCOT renewable energy supply 2008 to 2030 | TREIA
“I’m told current plans for batteries already exceed this capacity. These capacity values seem high, but they are in line with recent trends in new wind development,” he said.
Sterzing said regulators and traditional utilities could find themselves subject to “disintermediation” — in which the middleman in a transaction gets cut out of a process — if they don’t adjust quickly to new products and services.
“You figure it takes 10 years to build a coal plant. The old utility moves at that pace because of big, chunky additions that take advantage of centralization and economies of scale,” he said. “The retail consumers are not going to wait around when scarcity presents itself. There are substitute products on the market that are economic, and if we don’t get out in front of it, the consumers are going to do what they’re going to do, without concern for stranded costs or integrated operations. The regulators are going to have to pick it up, or the industry won’t be able to get out in front with integrated products and services that interface with batteries, distributed generation and electric vehicles.”
“It’s that process by where we set a vision, then come together to determine the technical problems that keep us from getting there, that has Texas in the lead,” said Tom “Smitty” Smith, a prominent Texas environmental activist and executive director of the Texas Electric Transportation Resources Alliance (TxETRA). “We’ve done well to tie ourselves with the vision of the future. We can move on to other things, because wind is now cool. We have to continue to capitalize on renewables.”
Dean Tuel, global vice president of sales for Younicos, an energy storage company, said economics will be the limiting factor in TREIA’s “50% by 2030” goal.
“It’s always economics. The cost of new technologies are always a challenge in the early phase,” said Tuel, whose company was acquired this month by Aggreko, a provider of mobile and modular power.
“We need to get to where we’re seeing 4- to 5-MW land-based turbines until we get the economics to where they should be,” ATG Energy founder Patrick Woodson said.
“The key is simply getting people to adopt new technologies and move away from their old way of thinking,” Tuel said. “How do you pull them in? Make the economic case.”
AEP Texas cited cost effectiveness in attempting to install two battery storage facilities in West Texas and classify them as distribution assets, the panel noted. The Texas Public Utility Commission rejected the utility’s proposal in January, but it opened a rulemaking to address “non-traditional technologies in electric delivery service” (Project 48023). (See PUC Opens Rulemaking on Distributed Battery Storage.)
Smith said the three-person PUC may be the best commission since Pat Wood III and Judy Walsh were among the vanguard deregulating Texas’ electric industry in the late 1990s. However, Smith said, the commissioners, who have all been appointed since September 2017, “don’t want to issue policy statements” and would prefer to see what develops during the 86th Texas Legislature when it convenes in January.
New energy policy is unlikely, Smith said, with a new House speaker and new chairs on its energy policy-setting committees.
“We’re at a point where not much may happen this session,” he said.
Ken Donohoo, a director with the Electric Power Engineers consulting firm after 25 years with Oncor, said what he called the “imminent grid” presents a crossroads for the transmission and distribution sector. He said decisions on the grid made today will affect how power is supplied for decades to come.
“The traditional grid is a one-way system. We’re headed to a multi-way system,” said Donohoo, pointing to distributed energy resources, two-way power flows, block chain and other new technologies changing the market dynamics.
“It isn’t just the power systems anymore,” he said. “It’s the communications; it’s the control. It’s the Internet.”
Donohoo described the imminent grid as being digitized, with remote control, self-regulation and a heavy emphasis on sensors collecting data.
“T&D planning must change and adapt. It’s full employment for planning engineers. If you have a son or a daughter, send them to [learn] planning and call me when they graduate,” he said.
“The decisions we make today will affect how power is supplied for decades. Whatever we are going to build today, we are going to have to live with it for the next 25 years. We have to understand what the future is bringing, and not blindly go with everyday reactions to what is cost-effective today.”
Cities Have Strategies to Meet Renewable Energy Goals
Representatives from host Georgetown and other Texas municipalities said their early investments in renewable energy have paid off — Georgetown officially reached 100% renewable power in July, while Austin is on track to meet its goal of 55% renewable energy by 2025.
Under a new “flexible path” strategy, San Antonio plans to generate about half of its power from renewable energy sources by 2040. Wind and solar energy currently account for about 22% of the city’s power.
“Our flexible path strategy is to make strategic decisions, but on a smaller scale,” said John Bonnin, vice president of energy supply and market operations for the city’s CPS Energy. “We want to plot a course that results in rates affordable for our community but avoid making multibillion-dollar mistakes.”
Bonnin said the strategy has already resulted in retiring 800 MW of coal-fired generation, with another 1.6 GW to come offline before 2026.
“Over the next several years, we have to develop and get consensus around a step-by-step approach to meeting customers’ needs 10 years from now, and meeting their needs in an acceptable way,” he said. “The flexible path is going to have to be just that, to satisfy all the affordability and sustainability criteria we have. We can shore up capacity with solar and wind. There will definitely be cheap power for sale over the next few years.”
“Georgetown has been a benefactor of the market, but when you start hearing about 800-MW, 600-MW drops in capacity, it begins to make you feel a little nervous,” said Jim Briggs, general manager of the city’s utility. “Will we be able to get new strategies into the market fast enough to make up the difference? In looking at batteries and distributed generation, the costs are moving targets.”
Khalil Shalabi, vice president of strategy, technology and markets for Austin Energy, said the city will be retiring the “lion’s share” of its thermal generation between 2020 and 2023. That means the utility will need DER, DG, storage and other “new tools” to pick up the slack.
“We can’t run [steam generation] forever,” Shalabi said. “It’s a problem, but it’s also exciting for us to deal with.”
Renewable Development Getting High Marks from Communities
Speaking on a panel discussing community-engagement strategies and lessons learned, Duke Energy’s Scott Macmurdo said the corporate renewable energy market is “going gangbusters,” pointing to a near doubling of last year’s 2.7 GW in deals because of consumer preferences.
“Companies are being held to account for what happens in their supply chains,” Macmurdo said. “Companies are taking ownership, and that’s one of the main drivers behind corporate renewable energy purchasing. The consumers care more and more about where they are sourcing these electrons. It matters with community engagement, because corporations are more sensitive about these issues.”
Susan Sloan, vice president of state affairs for the American Wind Energy Association, said consumer preference is one reason wind energy is still getting a favorable reaction in the state.
“We’re at a point now where we’re ready to start building again,” Sloan said, noting 5 GW of wind energy is currently under construction in Texas. “People are still interested in seeing more wind and using more wind. They’ve seen wind as a good neighbor and partner with oil and gas. It’s good for the economy; it’s good for the environment.”
Jeff Risley, chief strategy officer for Oklahoma-based consultancy Saxum, said whereas the industry generally receives strong community support, organized opposition has become more prevalent.
“There are organized players in this industry attempting to derail what’s happening with renewables. There’s lots of money behind them,” he said. “We deal with this all the time in Oklahoma. You have to combat those messages with the positives … about solar and wind development.
“We’re in the community, talking to people,” Risley said. “Then it’s figure out if they’re pro, con or in the middle. The middles are the ones we’re looking for.”
The formation of a Western energy market and who might control it were contentious topics of discussion at the fall joint meeting of the Committee on Regional Electric Power Cooperation (CREPC) and Western Interconnection Regional Advisory Body (WIRAB) near Phoenix last week.
Panelists also took on the topic of who will succeed Peak Reliability in the Western Interconnection as the company winds down its operations by the end of 2019. Both CAISO and SPP are vying for Peak’s reliability coordinator (RC) business, with CAISO poised to take on customers representing more than 70% of the region’s load. BC Hydro is also moving ahead with plans to set up an RC covering its own territory in British Columbia, Canada. (See CAISO RC Wins Most of the West.)
Peak CEO Marie Jordan said a major worry is that key employees will leave the organization before it hands off its responsibilities to its successors.
“As we’re going down this journey, and we’re closing the doors, slippage will be very hard to manage,” Jordan said.
In July, Peak made the stunning announcement that it would end its role as an RC and withdraw from an effort to develop a regional electricity market competing with CAISO. (See Peak Reliability to Wind Down Operations.) The Vancouver, Wash.-based company said it expected to shut its doors as early as Dec. 31, 2019, after transitioning its customers to other RCs. It was feedback from those customers commenting on Peak’s budget discussions that prompted the move to cease operations, Jordan has said.
In a panel Friday on RC services in the Western Interconnection, SPP and CAISO executives contended their organizations are best suited to provide RC in the West after Peak ends operations. Eric Schmitt, CAISO’s vice president of operations, said the ISO was already used to working with its western neighbors through its Energy Imbalance Market and other functions, while Bruce Rew, SPP vice president of operations, said the RTO had transitioned RC services before and could “make sure the lights stay on.”
The three-day meeting in Mesa, Ariz., addressed a dozen subjects including the reliance on natural gas for electricity generation in the West, cybersecurity for the grid, and customer-choice programs that are attracting large electricity loads away from investor-owned utilities.
On Thursday, wholesale market expansion in the West provoked a lively discussion among panelists, who debated the merits of CAISO leading a Western RTO — or whether an Eastern RTO such as PJM should tackle the job.
PJM has continued to express interest in developing an organized market in the Western Interconnection despite the downfall of Peak, its initial partner in the effort. (See Western Regionalization ‘No-brainer,’ PJM CEO Says.)
Peter Ristanovic | CAISO
Petar Ristanovic, CAISO’s vice president of technology, said the ISO was most competent to form a Western RTO and questioned what “Eastern entities” could bring to the West at a time when California is trying to reach its goal of relying on 100% renewable and other zero-carbon energy sources by 2045. Eastern states, he said, are still trying to make the transition from coal to natural gas that California went through years ago.
Today, California is dealing with the “ongoing onslaught of intermittent renewables,” such as wind and solar, and looking to a future that includes the possibility of millions of electric vehicles charging at night. In addition to traditional morning and evening peak demand, “Who knows, we may get three peaks,” Ristanovic said.
Therese Hampton, Public Generating Pool | LinkedIn
Therese Hampton, executive director of the Pacific Northwest’s Public Generating Pool, an association of 10 consumer-owned electric utilities in Washington and Oregon, said CAISO had started as a single-state entity while other organized electric markets, including PJM, were formed as multistate organizations.
She said a Western RTO would need a governance structure that was independent of California’s political leaders, unlike CAISO, and large enough to include a diversity of interests and representatives from multiple states.
Scott Miller, Western Power Trading Forum | LinkedIn
Her organization, she said, recently supported California’s AB 813. The bill, which failed to get a full floor vote in August, would have started the process of turning CAISO into a multistate entity by creating a governing board independent of the governor and legislature. (See Can Calif. Go All Green Without a Western RTO?)
Scott Miller, executive director of the Western Power Trading Forum, echoed her sentiments. Why, he asked, would Western states join a CAISO-led RTO if CAISO’s governance structure wasn’t altered, thus putting them “under the control of political elements in Sacramento”?
Maine regulators on Friday suspended hearings on Central Maine Power’s proposal to bring Canadian hydropower to the New England grid via a 145-mile transmission line across the state.
The move by the Maine Public Utilities Commission poses a significant setback for the Avangrid subsidiary’s New England Clean Energy Connect (NECEC) project. During an analyst call Wednesday, Avangrid CEO James P. Torgerson had said NECEC was close to gaining a certificate of public convenience and necessity from Maine and “on track” to receive all permits and final approvals in 2019.
In granting the motion to suspend by NextEra Energy Resources (Docket No. 2017-00232), the PUC also scheduled an Oct. 31 conference to discuss the additional process and schedule to be adopted in the proceeding.
CMP’s $950 million New England Clean Energy Connect project now faces uncertain delays after the Maine PUC suspended hearings on Oct. 26. | Avangrid
In a joint letter to the PUC on Oct. 24, generator intervenors and others supporting the motion, including the Natural Resources Council of Maine (NRCM), said CMP “has only recently and very tardily produced certain highly relevant documents previously requested by NRCM and the generator intervenors. Furthermore, there remains a substantial risk that other highly relevant documents will not be produced by CMP and reviewed by the parties until after the currently scheduled hearing dates or even the current the briefing deadlines.”
Massachusetts awarded its 9.45-TWh clean energy solicitation to NECEC last winter after the original winner, Eversource Energy’s Northern Pass project, was rejected by siting officials in New Hampshire. (See Maine Lawmakers Signal Opposition to NECEC.)
NRCM attorney Sue Ely said in a statement that “the PUC’s decision to delay hearings on CMP’s proposed transmission line is a welcome acknowledgement that this process has been moving too fast for a thorough analysis of this massive, incredibly complex and flawed project. … At the 11th hour, the company finally submitted tens of thousands of pages of documents that are critical to understanding the climate and rate impacts of the proposed power line.”
Some of the submitted documents contradict statements in the record made by CMP, she said.
The NRCM and generators contend that Hydro-Quebec will divert hydropower from other markets, therefore providing no reduction and possibly even an increase in greenhouse gas emissions.
“CMP also asserts that NECEC will suppress generating capacity market prices to the benefit of Maine ratepayers, thus raising the question whether Hydro-Quebec has such capacity to sell and, if so, whether it would clear the ISO-NE” Forward Capacity Auctions, the intervenors said.
“Lastly, CMP claims that NECEC offers winter reliability by reducing the need for natural gas in New England during extreme weather conditions, ignoring the potential increase in natural gas consumption that would occur in New York and Ontario if Hydro-Quebec’s exports were simply diverted from those markets into New England,” they said.
CAISO’s congestion revenue rights market showed unusual surpluses this summer because of higher congestion rents on Path 26, a major transmission line leading into Southern California.
In particular, there was a roughly $50 million surplus in August with sizable surpluses in July and September as well.
A CAISO forum addressed market performance and planning Wednesday. | CAISO
Deficits in the CRR market were far more typical than surpluses in 2017 and 2018. The atypical CRR revenue adequacy in August and September was one of the more notable revelations in CAISO’s Market Performance and Planning Forum on Wednesday.
“The main reason for the CRR surplus was congestion on Path 26,” said Rahul Kalaskar, the ISO’s manager of market validation analysis.
Kalaskar said there were high flows north to south this summer because of higher temperatures and gas prices. That led to higher energy prices and more expensive congestion pricing, boosting overall congestion revenues.
“The main reason for this high congestion is you had high gas prices, and there were some days where you had local outages,” Kalaskar said.
Western wildfires — and the threat of wildfires — created market uncertainty and contributed to higher prices, he said. Exceptional dispatches (out-of-market operations to ensure adequate generation) spiked in July and August in the ISO’s territory but diminished as the threat of fire and higher loads passed.
Other findings showed integrated forward market prices (which include day-ahead prices) in July and August spiking well above those in real time, but September saw a return of normal patterns. CAISO price correction events stayed high in August and September and Energy Imbalance Market-related price corrections surged in September too.
MISO and SPP could jointly create a smaller category of interregional transmission projects as early as next year to address costly congestion, the RTOs said Tuesday.
But the RTOs have not reached any decisions on the issue and will spend at least part of next year evaluating the effectiveness of a smaller project type to address historical market-to-market congestion, according to RTO staff speaking at an Oct. 23 MISO-SPP joint stakeholder meeting.
MISO Planning Adviser Davey Lopez said the projects could be any voltage and include tie-lines and interconnections or transmission projects wholly contained within the footprint of either RTO.
MISO said potential criteria could limit project costs to less than $20 million and require an in-service date of within four years of approval. The RTO is also suggesting that projects must pay for themselves within four years based on congestion savings. MISO is proposing to measure a project’s future congestion relief benefit against two years of historical congestion prior to the project study.
The criteria closely resemble those of MISO-PJM targeted market efficiency projects (TMEPs), created in 2017, which must cost less than $20 million, cover their costs within four years of service and be in service by the third summer peak from approval.
The RTOs cite high-priced congestion on market-to-market flowgates as the reason for creating a new smaller project type. Lopez said SPP’s Riverton-Neosho-Blackberry flowgate in Missouri may be ripe for such a project after costing MISO $18 million in congestion in 2017 and $9 million so far this year. Its congestion has been chronically expensive since the RTOs created it in 2017. (See “MISO M2M Payments to SPP Exceed $50M,” SPP Seams Steering Committee Briefs: May 2, 2018.)
“We’re getting close to $30 million on that particular flowgate in the last few years,” Lopez said.
He said new, smaller projects aimed at congestion relief are needed because the RTOs’ longer-term transmission planning process misses quicker transmission upgrade solutions.
But some stakeholders said congestion could be better solved by administrative means between the two RTOs rather than transmission buildout.
Lopez promised a “deeper dive” into the causes of congestion as part of the exploration into the project type. “As part of the process, it will cause MISO and SPP to look into the causes of congestion and if it will persist,” he said.
Early this year, Entergy argued that the MISO-SPP seam does not yet have a structured enough coordination process to develop smaller interregional projects. (See “Entergy Critical of MISO-SPP TMEP,” MISO, SPP Look to Ease Interregional Project Criteria.)
Other stakeholders called for more than two years of congestion data to justify creating a new project type, and staff from both RTOs said they will continue to collect flowgate data. Lopez said MISO plans to investigate individual flowgates and speak with transmission owners about the causes of congestion, much like it did in this year’s round of TMEPs.
MISO and PJM have so far recommended seven TMEPs, five of which received approval in 2017, with the other two up for approval this year. The projects are expected to cost under $25 million and reap about $132 million in benefits. (See MISO, PJM Endorsing 2 TMEPs for Year-end Approval.)
But some stakeholders contend that at least some of the market-to-market congestion issues can be traced to the RTOs’ separate interconnection procedures that don’t fully study how new generation projects will affect flowgates before granting grid access.
MISO and SPP current generation queue projects | SPP, MISO
Stakeholders have called for increased coordination in generator interconnection procedures, but the RTOs say they already study for impacts on each other’s systems and facilities in their affected-system study process and that interconnection staff currently meet face-to-face twice a year and hold monthly conference calls.
LITTLE ROCK, Ark. — SPP staff are dialing back an ambitious proposal to beef up the analysis behind generator retirements, promising to take “baby steps” in designing a “holistic process” in the face of stakeholder pushback.
Casey Cathey, who will soon become SPP’s manager of reliability planning, recently promised the Strategic Planning Committee that staff would focus on the “technical aspects” of evaluating generator retirements, saying he wants the issue to be an official item before the Markets and Operations Policy Committee.
“We want to show some traction,” Cathey told the SPC on Oct. 18. “What we really want is an overall process, so people can rally around it and say, ‘This is what we really want to do.’”
Quite the opposite happened when Cathey shared his proposal with the MOPC and SPC earlier this month. Stakeholders reacted negatively to the potential use of reliability-must-run contracts and involving SPP’s Market Monitoring Unit in the evaluation process.
SPC Chair Mike Wise, who told RTO Insider he was surprised by the presentation, was emphatic as he complained about the potential use of RMRs and having to possibly pay other generators’ fixed costs.
“This is a real reach in strategy and dangerous from my point of view,” said Wise, Golden Spread Electric Cooperative’s senior vice president of regulatory and market strategy.
“This could blow this up into a massive issue,” American Electric Power’s Richard Ross said during the MOPC discussion. “I encourage you to walk before you run.”
Cathey took Ross’ advice, saying staff would rely on an in-house white paper to flesh out the RMR process by creating a business practice and revising the Tariff.
“We’re not going to address the RMR contracts or the settlement aspects of fixed costs,” Cathey said. “We’ll get down to the technical aspects of how we figure out this thing. We’ll back this up a little bit.”
The Board of Directors and Members Committee is not scheduled to resume the discussion during their Oct. 30 meeting.
Staff brought the issue before their governance groups, saying an aging fossil fleet has increased the possibility of retirements in SPP’s footprint. Noting that retirements are evaluated in multiple processes with limited coordination, staffers said they want to ensure the RTO has an opportunity to study retirements and any resulting mitigations before the actual retirement date.
SPP generation requirements statistics | SPP
More than 4.1 GW of generation has been retired in SPP’s footprint since 2010, but another 2.4 GW is scheduled through 2019, and staff said they are beginning to see ad hoc studies on other potential retirements. Cathey said 77 different resources have been manually committed for reliability purposes, with the longest commitment for 74 days.
“The only mechanism we have right now is to run the resource,” he said. “You guys would not be properly compensated. Any costs you would incur are not included in our Tariff.”
Best Practices
While staff are proposing planning and operations assessments for retiring units, it was the MMU’s evaluation that drew most of the stakeholder feedback. The Monitor wants to guard against market power issues, focusing its analysis on whether the retirement would result in a scarcity of generation capacity or amount to an uneconomic decision indicating physical withholding behavior.
Executive Director Keith Collins said the MMU will review both technical and economic justifications, looking at the unit’s age and possible state or federal environmental requirements that might force it to retire.
Collins also said the Monitor would intervene, if necessary, in retirement applications before regulatory bodies.
“I’m not comfortable with you testifying as an intervenor in our state cases,” Southwestern Public Service’s Bill Grant said. “I have a lot of concerns with what you’re proposing.”
“My expectations are it would be a dialogue. If there’s a difference of opinion, we would talk about concerns before reaching the point where we’re talking to the state or other regulatory bodies,” Collins responded. “What makes the Market Monitor unique is that we have a particular view no one else does, including the states. It gets to the concept of a structural market issue, where your resource could create market power.”
The MMU’s proposed analysis would rely on a going-forward cost that measures avoidable costs if a generator is retired or mothballed. Going-forward costs include mandatory capital expenditures due to any environmental, safety or reliability requirements, fixed operating and maintenance costs, and property taxes, if applicable.
The Monitor plans to use going-forward costs to help determine whether a generator’s net market revenues cover enough expenses to allow it to operate as long as it financially should.
“The two questions we would ask are, one, does [the retirement] create undue market power, and two, is the retirement economic?” Collins said. “If we have a serious enough issue that comes up as a part of this process, we’ll do what we have to do. We would be questioning the economics. The reality is, we’re reaching out to state commissions and talking about these issues already.”
Collins said the concept is nothing new for Monitors, noting NYISO has a similar process and uses expected net revenues to help determine whether to retire units or build new generation.
Cathey said the RTO would “hopefully” not identify any issues in the process and instead allow a resource to retire.
“We looked at every other ISO in the U.S. This has been crafted on best practices,” Cathey said. “If you’re coming to us to retire, you’ve largely done your own homework. We don’t want to be a barrier to that. If we find something because of the way we operate, we would execute an RMR.”
“My members, my board, [do not] want to pay for fixed costs of other generators in the market,” Wise said. “We don’t have a capacity market; we have a capacity requirement. I pay for my fixed costs; I pay for my fixed requirement. We don’t pay for each other’s fixed costs. This would be a real shift for SPP and problematic for many consumers.”
“Let’s be realistic,” Cathey said. “We’re not looking to circumvent any state authority. RMRs are really a last resort.”
Cathey said staff will continue discussions with several stakeholder groups and begin development of a revision request. SPP plans to return to the MOPC in January with draft revisions.
SOUTHINGTON, Conn. — Battery storage, energy efficiency and offshore wind dominated the discussion at the Connecticut Power and Energy Society’s Future of Energy Conference on Oct. 24, along with the question: Who pays for all this progress?
“Storage is fascinating. Like the shapeshifter, it can do so many things,” said Katie Dykes, chair of the Connecticut Public Utilities Regulatory Authority.
The most cost-effective place to use and operate storage depends on the revenues being sought, Dykes said, noting that both a rate-based distribution plan and the wholesale energy market can provide a lot of services.
“We really need to get our distribution regulatory framework aligned with the wholesale energy market rules to knit together all those different values,” Dykes said. “Trying to get that price signal just right to help people value the benefits from these types of investments [and] doing that in a very holistic way is incredibly important.”
Anthony Marone, CEO of Connecticut-based utility United Illuminating, sees storage as working on both sides of the meter.
“Large-scale storage systems, regardless of who owns them, should be on the distribution side and controlled by the utility,” Marone said. “The stream of benefits should always be maximized for all ratepayers if they’re all paying for that.”
Marone also addressed the need to implement demand charges in planning for the increased use of electric vehicles. He noted that if EV adoption goes “through the roof,” the absence of such charges would mean utilities are “building a system and spending a lot of money where there’s no price signals that recognize that these things are having an impact on the system and everyone’s paying for it.”
Roger Kranenburg, vice president for energy strategy and policy at Eversource Energy, predicted that the coupling of electricity and transportation will change everything in the energy industry.
“The pie that we’re working on is no longer a slice of the pie; it’s the entire pie that we’re looking to modernize,” Kranenburg said. “Engineers love to complain, but they love challenges, and they usually solve them. Look at wind integration onto the system. The biggest challenge is regulators and companies working to balance who pays and who benefits.”
William Murray, vice president for state and electric public policy at Dominion Energy, which owns the Millstone nuclear plant in Connecticut, said New England’s challenge lies in becoming more dependent on natural gas as the pipeline infrastructure appears incapable of being adequately fed or permitted to expand.
Despite the industry’s success in keeping wholesale energy prices low, “we notice that customers don’t really care about the subcomponents of their bill; they want to know what’s … the total bill,” Murray said. “There are times when our residential rates in Virginia and North Carolina are very competitive with your industrial rates [in New England].”
Bill Luchon, senior manufacturing engineer and environmental leader at Hartford-based manufacturer Legrand, said energy conservation at first offers a lot of “low-hanging fruit” but then gets harder.
Legrand has reduced its energy intensity by 48.5% since it joined a Department of Energy initiative for manufacturers in 2011, “which is pretty impressive,” Luchon said.
A few years ago, the company heard about a free industrial assessment audit by DOE, “and they identified a whole bunch of opportunities, which equated to about $55,000 a year in electrical savings for things that we wouldn’t even consider,” Luchon said.
New Haven Public Schools COO Will Clark said he oversees the system’s $400 million annual budget and $1.6 billion construction program. “When I save a million dollars in energy … that essentially goes to pay for teachers and for buying the textbooks,” he said.
Renewable energy, energy savings and carbon footprint reduction are all important to New Haven residents, so good publicity helps win official support for projects, he said.
“If I can get the mayor or the superintendent on [the front page of the newspaper], I get a project put forward,” Clark said.
Mark Wick, a partner in Energy Innovation Park, a $1 billion data center being developed in New Britain, pointed out the project will feature a 19.98-MW fuel cell microgrid. “That is an industry that is very aware of renewable energy … and the amount of energy used.”
Matt Morrissey, vice president of Deepwater Wind, said Connecticut “punched substantially above its weight” in the first round of procurement for offshore wind.
Connecticut officials in June announced they will purchase 200 MW of output from Deepwater’s Revolution Wind project, adding to Rhode Island’s 400-MW procurement. (See Conn. Awards 200-MW OSW, 50-MW Fuel Cell Deals.)
As a result of drafting behind larger procurement processes in Massachusetts and Rhode Island, Connecticut obtained a 600-MW price for 200 MW of offshore wind and was also able to leverage Deepwater’s investment criteria, Morrissey said.
“On a job-per-megawatt-hour basis and investment-dollar-per-megawatt-hour basis, [Connecticut] actually beat both Rhode Island and Massachusetts,” Morrissey said. “Very savvy indeed for the state to do what they did.”
Deepwater will file for the procurement in the next few weeks, and the details will be public, Morrissey said.
Peter Shattuck, vice president for special situations at transmission developer Anbaric, said, “There are not a lot of great interconnection points to land 10 GW of new resources on the Eastern seaboard … so we have to think about how many lines we want to be stringing across the ocean floor.”
There is a potential to oversize the transmission grid in anticipation of the new resources and minimize the number of times needed to go through the complex planning process, he said. (See Anbaric Pushes Offshore Grid Plans.)
“The best economic results are where you plan for the wind, as in Texas … which has allowed them to put as much wind in their one state as we have all generating capacity in New England,” Shattuck said. “We know there’s a lot of offshore wind in Maine, but it’s not a big part of the mix right now. Why? Because we don’t have the transmission.”
