HOUSTON — At the Gulf Coast Power Association’s annual spring conference last week, ERCOT CEO Bill Magness once again moderated a panel of his counterparts from around the country, welcoming back MISO’s John Bear and SPP’sNick Brown. Joining the discussion this year was PJM’sAndy Ott, with a vacant chair left to recognize 2017 participant Steve Berberich of CAISO.
Magness asked Brown and Ott to explain their participation in the Western markets. SPP has been working to integrate the Mountain West Transmission Group since January 2017, while PJM has partnered with Peak Reliability to offer market services in the Western Interconnection through its PJM Connext subsidiary.
Brown pointed out that SPP is not a greenhorn when it comes to being active in the region. “We’ve worked with participants in the West the last 10 years, helping them to understand our markets,” he said. “The efficiencies, the increasing of reliable operations across larger areas, the integration of renewables … those are all things people are wanting.”
“It’s really education, trying to fill a void,” Ott said. “We’re fostering a discussion of competitive markets. Even if we’re not successful, we’ve had a positive influence. When we first got out there, we saw cultural differences, but we very quickly talked about a market for the West, by the West. We let them realize, ‘Wait a minute, I’ve got control,’ because it’s their assets, their region.”
In describing the value of RTOs to their members, Brown shared a story about a conversation he had with a current SPP participant, who had previously formed another organization consisting of member utilities.
The member asked Brown, “‘What are you going to say to convince me to turn over management of my assets?’
“‘Well, how did you do it within your organization?’” Brown said he responded.
“‘I pried it out of their cold, dead fingers.’
“I said, ‘OK, we can’t do that. We’re not going to do that. We’ve got to show the value proposition [of an RTO]. Quite frankly, that’s why you don’t have value in doing this by yourself anymore.’ That’s what the folks in all our footprints saw: the benefits.”
Asked what he was watching in the other RTOs, Bear pointed first to their response to FERC’s resilience initiative, saying “there are ways we could be more resilient.”
“The FirstEnergy situation in PJM … we’re interested to see how that gets dealt with,” Bear said, referring to FirstEnergy Solutions’ recent bankruptcy filing and plea for governmental protection of its nuclear and coal plants. (See FES Seeks Bankruptcy, DOE Emergency Order.)
“We’re also watching Andy’s guys to see how they do scarcity pricing. For SPP, we’re watching how they deal with all that wind, and how they do so well with 50%, 60% [wind penetration] levels. We can only simulate that.”
“My neighbors matter a lot to me. John and I are intertwined, and we have great working relationships between the two of us,” Ott said, noting his organization also learns from SPP. “A developing story is in New England, where they worry about fuel security. They only have a couple of interstate pipelines, and we have 25. How they deal with that fuel-security problem will affect us.”
Like SPP, MISO is also working to accommodate a large influx of wind energy and other renewables. Bear said the ISO had 100 MW of renewable energy in the mid-2000s, but that has now grown to 18.5 MW.
“We had people telling us that with up to 5 GW [of renewables], we would crash the system,” he said. “We’ve done a lot of transmission build to disperse that [energy] and pass the benefits around. We’ve also had to design products to handle the wind. We had a lot of wind turbines that wouldn’t turn down, but now, we incentivize them to do the right things.”
Magness did not let the round table end without uttering a word he said is heard these days at every self-respecting conference: blockchain.
“There, I said it!” he said, peering at his audience.
Later, upon begin congratulated for mentioning “blockchain,” Magness brought up another futuristic word from a bygone era: “Plastics!”
WILMINGTON, Del. — Has the door for revising PJM’s Capacity Performance calculations been opened too far? Some stakeholders fear so after members at last week’s Markets and Reliability Committee meeting endorsed revisions to an issue charge for an initiative examining the calculation of the balancing ratio used in setting capacity offer caps.
Originally, the market seller offer cap (MSOC) equation was out of scope in the inquiry being conducted by the Market Implementation Committee and members were only focused on how to determine the balancing ratio.
The balancing ratio needs to be addressed because it is currently based on the number of performance assessment intervals PJM experienced in the past three years, and it can’t be determined if there are no such events. That became a reality this year, requiring PJM to reuse last year’s as a stopgap until a new calculation is developed. (See “Stopgap Balancing Ratio OK’d Despite Questions,” PJM MRC/MC Briefs 10-26-17.)
Beyond the balancing ratio, the issue charge also allows for evaluating how many assessment intervals are assumed in calculating the nonperformance charge rate. The current assumption is 30 intervals per year, which some stakeholders have argued is too high.
But Joe Bowring, PJM’s Independent Market Monitor, pointed out that changes to the nonperformance charge can affect the MSOC, so the MIC needs the latitude to consider changes to it as well. It’s important to maintain the consistent relationship between the nonperformance charge rate and the MSOC, said PJM’s Pat Bruno, who was presenting the proposal.
“We can’t keep the equation ‘net [cost of new entry] times B’ as the default offer cap out of scope with this issue charge because any changes we make with the nonperformance charge rate may impact that default offer cap equation,” he said.
Exelon’s Jason Barker questioned that position, arguing that FERC approved the specific MSOC equation — the net CONE for a unit’s technology class multiplied by the balancing ratio. He said all the necessary assessment-interval changes can be made while keeping “the FERC-approved tether to net CONE” by ensuring the interval calculation remains consistent throughout the formulas, a point on which Bruno agreed.
Barker said that — and not a potential wholesale re-evaluation of the MSOC — is what he believed stakeholders were agreeing to when they approved the issue charge. Other stakeholders agreed.
“I don’t think there’s anything in the issue charge as it stands now that would prevent us from completely changing the nonperformance charge rate,” Bruno acknowledged.
But Bowring argued there’s nothing “magical” about the current MSOC and that FERC approved the logic through which the equation was developed.
“You have to address this additional question if all of these issues are at play, which they are at the moment,” he said.
Barker said he couldn’t endorse the widened scope and encouraged others to vote against it as well.
Other stakeholders voiced concerns about the potential effect on other market mechanics, but Barker’s lobbying fell short. The proposal was endorsed with five objections and one abstention.
Offer Cap Walk Back Stalled
PJM’s hope to return to previous language over energy market offer caps was dashed after stakeholders agreed with Bowring that the previous rules also weren’t correct.
Members approved the current Manual 11 language at the October 2017 MRC to comply with FERC Order 831. PJM staff subsequently discovered the revisions restrict market-based offers to $1,000/MWh, contradicting language in the Operating Agreement. The proposal would have reverted to previous rules that market-based incremental energy offers may not exceed $1,000/MWh unless the cost-based incremental energy offer is greater than that amount. In that case, the market-based incremental energy offer is capped at the lesser of the cost-based incremental energy offer or $2,000/MWh.
The current proposal was pushed through PJM’s stakeholder process unusually quickly, with a first reading at the Members Committee webinar just three days before the MRC meeting. PJM’s Rami Dirani said the quick turnaround was necessary to maintain consistency because the order became effective on April 12. He described the return to the prior language as “very straightforward,” but Bowring disagreed.
“It doesn’t strike me as being so straightforward,” he said, noting that the previous rules didn’t address PJM’s obligation to verify cost-based offers ex ante — based on forecasts — and ensure that price-based offers not exceed cost-based offers of more than $1,000.
Carl Johnson, representing the PJM Public Power Coalition, noted that many Manual 11 changes were being discussed in October, “so maybe it just slipped our focus. But I thought we knew what we were doing then, and it’s clear from reading the manual language that we didn’t.”
The changes were originally made to reduce complexity, Dirani said.
“The inclination would be to spend a little more time on this rather than move another … rule that is not right,” Johnson said.
Other stakeholders agreed.
Calpine’s David “Scarp” Scarpignato asked that PJM return with some comparison of potential rule changes.
“I need to know more than just the mechanics,” he said.
“I’m sure it seems simple; you’re going back to previous language. So I’m sure it felt simple, but it has obviously led to further questions,” said Adrien Ford with Old Dominion Electric Cooperative.
Staff agreed to send the issue back to the MIC for discussion but said they aimed to get feedback in time to have a proposal prepared for a vote at next month’s MRC.
Price Formation Reshuffle
PJM’s Adam Keech outlined staff’s plan to address energy market price formation changes in accordance with the Board of Managers’ request that stakeholders break the issue into pieces so that less controversial changes can be implemented sooner. The board made its request in a letter April 11. (See PJM Board Seeks Reserve Pricing Changes for Winter.)
The plan breaks potential changes into short-, mid- and long-term goals that correspond with the board’s request that some reserve market changes be ready for implementation by next winter and that other energy market changes be prepared for next spring.y
In the short term, PJM plans to focus on the synchronized reserve market, dynamic reserve zone modeling, simplifying the operating reserve demand curve (ORDC) and fast-start pricing if FERC approves the proposal PJM has already filed.
The mid-term topics for the first quarter of 2019 would include developing a 30-minute reserve product, along with additional revisions to the ORDC and fast-start pricing.
The long-term plan would extend the implementation of integer relaxation and look to add shortage pricing to the day-ahead market.
“My interpretation of the discussions [at the most recent meeting of the Energy Price Formation Senior Task Force] was there were no objections to moving forward with that,” Keech said.
Greg Poulos, the executive director of the Consumer Advocates of the PJM States, said his members don’t necessarily see the need to make these changes, “but we are aligned with the goals” of analyzing the situation to see if any changes are warranted.
The consumer advocates are particularly interested in cost-impact analyses, he said.
Stakeholders OK Manual, Operating Agreement Changes
Members approved changes to Manual 12: Balancing Operations to incorporate rules approved by FERC in November regarding reviews required for approval of pseudo-tied generators. The changes were endorsed with two objections and three abstentions. (See “External Capacity,” PJM PC/TEAC Briefs: March 8, 2018.)
Stakeholders also endorsed unanimously several manual revisions and other operational changes:
Manual 14A: New Services Request Process. The revisions clarify language to match existing procedures and add language to describe in detail system impact study (SIS) and interconnection feasibility study analyses. In January, a FERC administrative law judge issued an initial decision finding that PJM’s process is unjust and unreasonable because of a lack of transparency (EL15-79). On Feb. 20, PJM filed a brief on exceptions challenging the ruling. (See FERC Judge Faults PJM, TOs on Transmission Upgrade Process.)
Manual 14B: Regional Transmission Planning Process. The revisions are the result of a periodic review that identified several administrative changes, including a revision to the generator deliverability procedure and adding the Ohio Valley Electric Corp. to the western region study area definition. (See “Transformer Consideration Changed for Gen Deliverability,” PJM PC/TEAC Briefs: March 8, 2018.)
Manual 28: Operating Agreement Accounting. The revisions address changes to comply with FERC Order 825 implementing five-minute settlements. Also makes a technical correction for the revenue data used to calculate settlements for generation resources. (See “Order 825 Implementation Moves Forward,” PJM Market Implementation Committee Briefs.)
Revisions to the Operating Committee charter to replace the term “spinning reserve” with “synchronized reserves” to match the language in PJM manuals.
FirstEnergy announced mixed first-quarter earnings Monday, along with a potential path to exit the bankruptcy of its merchant subsidiaries.
The “agreement in principle” with two groups of “key” creditors that represent most of the outstanding debts for FirstEnergy Solutions (FES) includes $225 million in cash and a tax note of $628 million due before 2020, according to a company financial disclosure filed with the U.S. Securities and Exchange Commission.
Additionally, a $787 million unsecured claim would be allowed for creditors of the company’s Bruce Mansfield coal-fired plant in Pennsylvania, where a fire damaged two of the facility’s three coal-fired units earlier this year and two workers died from exposure to hydrogen sulfide gas in August, according to company filings. Four other employees were injured. The claim would be allowed against FES and its subsidiaries, FirstEnergy Generation and FirstEnergy Nuclear Generation.
Although FirstEnergy’s Allegheny Energy Supply (AE Supply) subsidiary hasn’t filed for bankruptcy, the agreement would also transfer to creditors its ownership of the Pleasants coal-fired plant, for which it hasn’t found a buyer. (See FirstEnergy Selling Merchant Fleet Despite NOPR.)
Earnings
The agreement came as the company also reported unadjusted first-quarter earnings of $1.2 billion ($2.54/diluted share), which improved from $205 million ($0.46/share) during the first quarter last year. Operating earnings of 67 cents/share improved from 52 cents during the same period in 2017 but missed expectations by 1 cent. Revenue increased to approximately $3 billion compared with $2.9 billion a year ago but remained several hundred million dollars below analysts’ expectations.
The company attributed the improved performance to shedding its beleaguered merchant generation fleet.
FirstEnergy’s coal-fired Pleasants Power Station in West Virginia would be signed over to creditors as part of an agreement announced Monday that would allow the company to exit the bankruptcy proceedings of its merchant-generation subsidiaries
“Today, we are pleased to report strong earnings that represent FirstEnergy as a fully regulated company,” CEO Charles E. Jones said.
The company raised its forecast range for unadjusted earnings for the year to $3.61 to $3.91/share, but it announced a gloomier forecast for next quarter. Unadjusted earnings are expected to drop to no more than 4 cents/share and could fall to a loss of 6 cents. Operating earnings are expected in the range of 47 to 57 cents/share.
Agreement Conditions
Company executives clarified several of the agreement’s points during a conference call on Monday to discuss the quarterly earnings with financial analysts.
One of the agreement’s conditions allows that if more than 60% of unsecured claims are recovered, FirstEnergy would receive 50% of any additional recovery. Jones acknowledged that such a situation would include any federal bailouts, such as those the company has requested through the Department of Energy, but emphasized that his interest is in keeping the plants open for the well-being of the communities in which they’re operating.
“We’re highly motivated to get support for those generating assets because it would be a mistake for our country for them to close,” he said. “I’m going to keep fighting for support for those plants, because it’s the right thing to do. If it gets to the point where it exceeds the threshold that we’ve got in this agreement with creditors, then, yes, we would share some of that, but that’s not why we’re doing it.”
In exchange for assistance from FirstEnergy during restructuring, the settlement would release the parent company from all claims, including decommissioning obligations for any of the nuclear plants if they are closed as the company has announced, Jones confirmed. (See FES Seeks Bankruptcy, DOE Emergency Order.)
FirstEnergy would waive some intercompany claims and maintain all previously announced guarantees, including pension obligations for FES employees. Creditors agreed to “use their best efforts” to get remaining creditors to join the settlement by June 15.
The agreement must receive sign-off from a federal bankruptcy court in Ohio, along with the boards of directors for FirstEnergy and its subsidiaries, including FirstEnergy Nuclear Operating Co. (FENOC).
FES and FENOC voluntarily filed for Chapter 11 bankruptcy on March 31. FES is FirstEnergy’s merchant generation and retail marketing subsidiary, while FENOC operates FES’ three nuclear plants. The decision, while expected for some time, is nonetheless creating ripples of uncertainty throughout the industry. (See FES Bankruptcy Creating Additional Uncertainty.)
Houston-based utility CenterPoint Energy announced Monday that it will acquire Vectren in an approximately $6 billion deal expected to close in the first quarter of 2019.
CenterPoint will pay Vectren shareholders $72 for each share of Vectren common stock — a $6.45 premium to Friday’s closing price — and assume all outstanding Vectren net debt. Hours after the announcement, Vectren closed Monday at $70.31 while CenterPoint ended the day at $25.94/share, down 31 cents.
Vectren headquarters in Evansville | Hafer Design
The merged company will retain the CenterPoint name and its Houston headquarters. CenterPoint will also maintain Vectren’s Evansville, Ind., headquarters for the company’s natural gas utilities and Indiana electric operation. The company will serve more than 7 million customers, operate electric and natural gas delivery operations in eight states and hold about $29 billion in assets.
The merger agreement has been approved unanimously by the boards of both companies, though the deal still requires approvals from Vectren shareholders, FERC, the Federal Communications Commission and regulators in Indiana and Ohio. CenterPoint said it expects to maintain a 5% to 7% annual earnings per share growth target in 2019 and 2020, excluding any one-time charges related to the merger. Both CEOs said the move will benefit their companies.
“By combining our two highly complementary companies, we are creating an energy delivery, infrastructure and services leader that will drive value for our shareholders and customers, while enhancing growth opportunities for our businesses,” CenterPoint CEO Scott Prochazka said in a statement.
“With CenterPoint Energy, we’ve found the right partner to begin the next chapter for Vectren and our family of companies. … Together, we will be a stronger, more competitive company that will be well-positioned to continue to provide value for our stakeholders in the years to come,” said Vectren CEO Carl Chapman.
Prochazka will remain CEO of the combined company. All other executive positions will be announced “prior to or in conjunction with the closing of the merger,” the companies said. CenterPoint said it will establish an executive position in Evansville, Ind., to handle natural gas utility operations and a chief business officer for Vectren’s electric business to directly report to the CenterPoint CEO and “spearhead southwestern Indiana’s electric grid modernization and generation transition initiatives recently underway.”
Earlier this year, Vectren announced it would build an 800- to 900-MW, $900 million natural gas plant in southwestern Indiana and a 50-MW, $75 million solar farm about 60 miles from the gas plant site. The new generation would replace three of Vectren’s coal-fired plants. The proposed gas plant still requires approval from the Indiana Utility Regulatory Commission. The company is also set to complete construction this year on two solar farms near Evansville that will produce 4 MW combined.
Prochazka and Chapman told the Evansville Courier & Press that they expect the merger will reduce Vectren’s 5,500-person staff but that it was too soon to say where, or how deep, the cuts will be.
The company provides electricity to about 145,000 customers in Indiana and natural gas to more than 1 million customers in Indiana and Ohio. Vectren also owns non-utility businesses Vectren Infrastructure Services Corp., which provides underground pipeline construction, repair and replacement services, and Vectren Energy Services Corp., which offers performance contracting services and renewable energy project development. CenterPoint said it intends to continue operating both companies.
CenterPoint currently delivers electricity to more than 2.4 million customers in the greater Houston area and serves another 3.4 million customers with natural gas operations in Arkansas, Louisiana, Minnesota, Mississippi, Oklahoma and Texas. The company employs nearly 8,000 people.
CAISO last week provided details on its plans for major changes to improve the alignment of its day-ahead market with real-time demand by introducing more scheduling granularity and other refinements.
Nearly 150 participants joined a conference call Wednesday at which the ISO discussed technical aspects of the revised straw proposal it issued April 13. CAISO has also proposed extending the proposed changes across the Western Energy Imbalance Market (EIM).
As currently proposed, the changes would address forecasting uncertainty in the day-ahead that is currently left to the real-time market to resolve, CAISO Senior Design Policy Developer Megan Poage said during a presentation.
The proposal would introduce 15-minute scheduling in the integrated forward market, which procures the generation needed to meet forecast demand. It would also create a day-ahead imbalance reserve market product and combine the integrated forward market and residual unit commitment. The third major prong in the initiative is to procure imbalance reserves with a must-offer obligation to submit economic bids in the real-time market.
“These three elements are dependent on each other. They must all be introduced at the same time,” Poage said, adding that “We’ll be moving toward a co-optimized day-ahead market run.”
The initiative, which was announced in December, is seen as a possible forerunner for a new Western RTO market structure by introducing a day-ahead market into the EIM, which is currently only a balancing market. (See CAISO Day-ahead Could be Tailored for West.)
“Grid infrastructure has advanced, the resource fleet has changed and the policies regulating operation of the grid have evolved (i.e. FERC-mandated 15-minute scheduling in real-time energy markets),” the ISO said in the straw proposal.
The proposal is intended to help manage excess solar generation in the middle of the day and make it possible to also reduce generation output. The current structure does not allow the ISO to decommit resources that were scheduled in the integrated forward market.
CAISO said the current hourly scheduling structure causes the day-ahead forecast to be higher than actual demand, resulting in “downward uncertainty,” in hours 1 to 12, and mismatches between day-ahead forecast and actual demand in hours 20 to 22.
CAISO says the current hourly scheduling structure causes “downward uncertainty” between day-ahead forecast and real-time demand in hours 1-12 and “granularity difference” in hours 20-22 | CAISO
Based on comments from market participants, CAISO changed the proposed 15-minute and five-minute imbalance reserves products in upward and downward directions into a single product for both directions. To address five-minute needs, CAISO would create sub-regions for the imbalance reserves product.
It also provided additional information explaining certain formulas it plans to use in the new day-ahead market, data analysis and proposed methodologies to determine imbalance reserves requirement, as well as a settlement and cost allocation worksheet for use by potential market players.
Overall, CAISO said, the changes will help decarbonize the electric grid, improve reliability as the system changes and create more market benefits across the region. The goal is to present the proposal to the EIM Governing Body in August and the ISO Board of Governors in September.
SANTA FE, N.M. — In an American West city known for its artists, writers and the beauty of its barren desert environment, state regulators and others last week discussed difficult grid reliability issues and the more vicious side of nature.
New Mexico State University’s annual Current Issues Conference has a reputation as a more informal gathering than other industry gatherings. A major topic at this year’s meeting was the severity of the 2017 hurricane season, in which grid resilience was tested in Texas, Florida and the Caribbean.
Industry consultant Alison Silverstein told the forum that the duration, magnitude and “customer survivability” of electricity outages are metrics that could be used to measure grid resilience. The grid is operated for the benefit of customers, she said, and resilience should be measured in “customer-based” terms.
Silverstein was an author of the Department of Energy grid study released last August but later criticized the department when Energy Secretary Rick Perry used its findings in his proposal that FERC order price supports for coal and nuclear generators with onsite fuel. (See Author of DOE Grid Study Disputes Recommendations.)
Perry’s Notice of Proposed Rulemaking was rejected in January by FERC, which instead opened a new resilience docket.
Silverstein told the forum that the technical conclusions she reached did not align with the department’s contention in the NOPR that coal and nuclear plant retirements were a reliability threat. “They apparently didn’t read the results of their own study,” she said.
Regulators shouldn’t overly focus on generation-based outages because 90% of outages occur in the distribution system, Silverstein said, and big weather events don’t usually affect power plants. Fewer than one in 10,000 customer outage minutes were caused by generation shortfalls.
Coal plants forced to retire since 2002 were old, inefficient and lacked the flexibility that today’s grid needs, Silverstein said. “Regulations were not the cause of the retirements,” she said, adding that fuel diversity has improved in areas where coal plants have retired.
Coal and nuclear subsidies are not the answer and would “cost a fortune,” she added.
There are many ways to improve resilience and reliability, she said, mentioning many of the topics discussed throughout the two days of the forum: distribution system improvements, situational awareness, emergency drills, system recovery and black start capabilities.
“Customer survivability” includes things like backup generators, rooftop solar and emergency supplies like flashlights. “You are already doing a lot of these measures,” Silverstein told the regulators.
Hurricane Response Ongoing, DOE Official Says
DOE Deputy Assistant Secretary Devon Streit discussed the department’s response to the hurricanes and natural disasters of 2017, an effort that is still ongoing. She said the department had response efforts in Texas, Florida, Puerto Rico and the U.S. Virgin Islands.
“We learned that island response is tough,” she said, mentioning not only the difficulties of restoring electric infrastructure in a remote environment but also the challenges of operating without facilities like radar, without which planes cannot land. Ships could not transport electrical equipment because they were carrying food, medicine and other critical supplies.
DOE’s Office of Infrastructure Security and Energy Restoration (ISDER) is responsible for energy sector preparedness and response, including electricity, oil and gas, and cybersecurity. It studies threats and examines hazards as well as holding exercises. It is responsible for communicating with federal and state agencies on what is happening on a near-hourly basis, she said in a presentation.
“We are still active for Hurricane Maria,” a response now in its 236th day, she said.
Streit discussed the value of situational awareness and mutual assistance projects, such as utilities sharing equipment. “What happened in Puerto Rico or Virgin Islands could happen in other places,” she said.
Texas Official Discusses Harvey Response
Public Utility Commission of Texas Chairman DeAnn Walker described how she went to her commission’s State Operations Center to conduct the response during Hurricane Harvey, which she said was “a very, very different storm than previous storms such as Ike and Rita.”
Walker said that in the first time in her experience, mobile substations were brought in because “we had substations flood that had never taken on water the whole time they were built.”
At the operations center, the PUCT worked on grid restoration with utilities and state and federal officials, including DOE, the U.S. Army Corps of Engineers, the Federal Emergency Management Agency and the Department of Homeland Security.
Harvey was the largest rain event in U.S. history, dumping an estimated 40 to 60 inches of water in southeast Texas and southwest Louisiana. ERCOT lost 12,000 MW of generation as gas-fired plants were evacuated or flooded, and coal plants and wind turbines were shut down. (See Weeks Later, Utility Officials Still Awed by Scale of Hurricane Harvey.)
VANCOUVER, Canada — The three RTOs vying to organize Western electricity markets on Thursday faced off before an audience of utility regulators in what one state commissioner billed a “beauty pageant.”
“Thank you for competing,” Montana Public Service Commission Vice Chairman Travis Kavulla jokingly told representatives of CAISO, SPP and PJM. Kavulla is co-chair of the Committee on Regional Electric Power Cooperation, which hosted the panel at its spring meeting in the Coast Coal Harbour Hotel.
The regulators were there to examine the possible benefits and drawbacks of the competing grid operators’ efforts to sign up utilities in a region that has been historically resistant to organized markets. (See CAISO Bid for Western RTO to Face Competition in 2018.) They, and other industry watchers, also learned what region PJM is focusing on in developing its Western market partnership with Peak Reliability.
Little Rock, Ark.-based SPP has been running its Integrated Marketplace since 2014, after previously operating a balancing system like CAISO’s Western Energy Imbalance Market (EIM). The RTO last year entered membership negotiations with Mountain West Transmission Group, a partnership of seven transmission-owning entities within the Rocky Mountain region of the Western Interconnection. The effort hit a significant roadblock late Friday when Xcel Energy announced it was pulling out of the group and the negotiations with SPP because of the “limited benefits” for its customers in integrating into the RTO. (See Xcel Pulls out of Mountain West, Endangering SPP Integration.)
“There are benefits from operating together” in an RTO, SPP Chief Operating Officer Carl Monroe told Western commissioners. “A natural inclination we would have is to look west.”
“We’ve got another unique situation in that we’re the only one connected to ERCOT,” he said.
Monroe touted the fact that SPP’s Board of Directors cannot express a decision without the consent of the RTO’s Members Committee, which provides each market participant a vote over market initiatives presented to the RTO board.
He also pointed out that SPP has functioned as a reliability coordinator (RC) for 20 years.
“And how that interfaces with the market … that was one of the key issues we dealt with in the market,” Monroe said. “These are hybrid markets. … They have to be designed to protect reliability itself.
“Our job one is to keep the lights on — reliability,” he added. “Even the economics don’t make sense if you’re not reliable.”
SPP’s market has been efficient for its members, he said.
“The capital costs of putting the market in — we recovered those within six months,” Monroe said, adding that the SPP footprint today carries 5 GW less generation than it would “if we weren’t running the market.”
He also pointed to SPP’s expertise in integrating large volumes of renewables.
“Of course we’re in a wind-rich area. We just set a record when 63% of the load was served by wind,” he said. “That could not have been done unless on a regional basis.”
“We actually do interregional coordination,” Monroe continued. “This is one of the things we’ll need to do within the West itself, is making sure we coordinate all the activities, whether it’s transmission planning, transmission operations, reliability coordination, market activity. All those things will have to be coordinated with the other parties that border whatever footprint we finally get around to.
“Part of the strategy going forward is being open to those parties who want us to do these services for them,” Monroe said.
“As you all know, many states in the West are aggressively pursuing more renewables,” CAISO CEO Steve Berberich said.
With a fleet heavy in renewables, ramping and overgeneration become “a focal point” for the ISO, he said.
“Security-constrained economic dispatch — in other words, an optimized market — is the best way to run the grid as efficiently as possible, and the sharing of resources is the best way to solve our critical need collectively to support the variability of renewables and the induced ramps,” Berberich said. “Further, the zero-marginal-cost power is better shared at a lower cost for all of our customers. We share this view with our [SPP] friends from Little Rock. You’ll also hear that from our friends from PJM in Philadelphia.”
Berberich trumpeted the EIM’s $250 million in member net benefits since it was launched in 2014. CAISO last year proposed to expand the EIM to include day-ahead transactions without transitioning the market into a full RTO. The ISO has also announced it will withdraw from Peak Reliability as an RC and provide reliability services to other balancing authority areas in the West.
He acknowledged that the EIM’s implementation of a day-ahead market will require the ISO to resolve approaches to resource adequacy and transmission compensation.
“Those are solvable, and we’ll continue to give deference to state control over resource mix and capacity margins. We also expect the EIM Governing Body to morph into a broader governing body with at least some joint decisional authority with the current [CAISO] board of directors,” he said.
CAISO expects to offer the combined EIM and day-ahead market at a cost significantly below the ISO’s current grid management charge, Berberich said. It also intends to offer the same reliability services as Peak at a “significantly reduced” cost.
“When you cut through it all, the fundamental markets are all the same. … What is different in our market, however, is the sophistication of our optimization and how it supports renewables, steep ramps and distributed generation aggregations,” Berberich said.
He said the ISO doesn’t foresee the need for any new transmission to “support the transformation into a regional market.”
On the issue of governance of an expanded ISO, Berberich told the commissioners that the “main pathway” is to change the existing governance model through legislation at the state level in California.
“The alternate pathway is to continue to evolve our governance according to the Energy Imbalance Market’s governing model, and with a day-ahead market, that will necessarily involve decisions on transmission compensation and some form of resource adequacy, both potentially having input from the [EIM] Body of State Regulators,” he said.
“Some of the ISO brethren say the Peak/PJM market offering is a market by the West, for the West, which misses what has already occurred in the Energy Imbalance Market. Participants are certainly not guests of the ISO, rather, they help form the market,” Berberich said.
The ISO’s job is to “listen to whatever the West wants and do our best to provide the value inherent in our interconnected systems.”
“When do we need to move to this new market? Soon, we think. We believe it will provide the most efficient way to streamline new transmission planning and upgrades, reduce the need for more capacity and reduce the need to curtail valuable clean resources. It provides the greatest value with the geographical and resource diversity that the West is blessed to have.”
“We believe there’s a very real opportunity for the utilities in the West to pursue the potential for the creation of a separate market,” said Stu Bresler, PJM senior vice president of markets and operations.
Bresler was speaking on behalf of the joint proposal between Peak Reliability and PJM Connext (a PJM subsidiary) to develop new wholesale market structures for the West. Like the CAISO EIM day-ahead expansion, it would fall short of creating a full RTO in the near term, while creating a foundation for one in the future.
Kavulla asked: “What area are you focusing on? Is it an area with lots of trees and hydro, or lots of sun?”
“We’re focusing primarily in the Southwest,” Bresler replied.
“The value proposition — and Steve has already said it before I had a chance to get up here — is a market for the West and by the West,” Bresler said. “What we are really leveraging here is the combined knowledge of our expertise of both of our organizations.
“PJM has proven its ability to promptly deliver on its commitments,” he said, citing PJM’s pledge to complete a business plan with Peak by March 30. (See Peak/PJM Enter Western Market Commitment Phase.)
“We have also been sharing the full plan with a set of key entities in the Western Interconnection that could potentially form the basis for a separate market out here in the West, should they decide to pursue that,” he said.
Striking a similar note to SPP’s Malone, Bresler said that wholesale electricity markets exist for the sole purpose of reinforcing grid reliability.
“That’s why we develop them; that’s why we operate them.”
Bresler said markets are intended “to ensure that physical asset owners have the financial incentive to act in a manner as to reinforce grid reliability.” Key to that is ensuring that market prices reflect actual operating conditions, and that “those prices are transparent to market participants in real time.”
“And that transparency and that reflection of actual operating conditions is what builds the confidence of the physical asset owners that the dispatch instructions delivered by the system operator are in their financial best interests. That financial best interest is a powerful motivator that supports reliable grid operations,” he said.
“We believe that the bulk of trading activity actually occurs in the bilateral markets,” Bresler said. “That is really an appropriate way for things to occur because it is what allows market participants to best manage and therefore minimize their risk.”
Bresler said the Peak/PJM business plan — which has not been made fully available to the public — shows that “with a large amount of participation in a market in the West, the production cost savings become very substantial.”
Lauding Peak’s RC capabilities, Bresler said that much of the hard work of starting up a regional market is already complete based on Peak’s West-wide model and the processes and mechanisms in place to support reliability.
“Really, the smaller part is layering [the market] on top of those reliable grid operations,” he said.
PJM’s “Day 1” market offering would consist of a day-ahead and real-time market.
“Some options that could be included as well, should participants want it, we could operate ancillary services. We could also add [financial transmission rights], but that’s not a requirement for Day 1,” Bresler said.
Based on feedback from potential participants, Bresler said Day 1 won’t include a resource adequacy construct or capacity market; consolidation of transmission tariffs; provision of transmission service; and regional or sub-regional transmission planning.
On one key issue, Bresler sought to score points from commissioners overseeing utilities already participating in the Western EIM.
“I don’t think of the establishment of the market as being exclusive of participation in the EIM,” he said.
Bresler noted that Peak and PJM had envisioned getting a “critical mass” of commitments from market participants by May or June, but they have extended that timeline to determine a “go or no go” decision on the market by the fall.
Kavulla asked Bresler when Peak/PJM anticipated releasing its full business plan for public review.
“We don’t really have any plan to do that. If members do decide to take the next step, we would take the decision with the members to do that,” Bresler said.
Bresler wrapped up his moment in the spotlight by echoing Berberich’s conclusion: “If utilities in the West want a full market … there’s not a better time to do it than now.”
BOSTON — Energy storage deployment will likely grow to 35 GW by 2025 as consumers, businesses and government agencies increasingly support the technology, industry experts said last week.
“Our industry created the momentum for the unanimous support to unleash the benefits of storage through FERC Order 841,” Energy Storage Association CEO Kelly Speakes-Backman said at her organization’s 28th annual conference. “This is a watershed moment, friends, this is our moment.” (See FERC Rules to Boost Storage Role in Markets.)
The industry’s growth will create hundreds of thousands of jobs, result in $4 billion in cumulative operational savings and avoid 3.6 million metric tons of CO2 emissions and 1,000 metric tons of CO2 equivalents, including nitrogen and sulfur oxide, Speakes-Backman said.
“On a regular basis, our teams are in contact with ISOs and RTOs who are seeking guidance in how to create markets and support rules that enable more storage on the transmission level, distribution level, in businesses and in homes,” she said.
Massachusetts Gov. Charlie Baker opened the conference April 18 by saying that energy storage’s ability to shave peak demand “may be greater than anything else.”
Baker mentioned the “very unusual winter here in New England and in Massachusetts … where we had subzero temperatures for almost two weeks,” during which the region’s generators burned through nearly 2 million barrels of oil, more than twice the amount used during all of 2016. (See Van Welie: ISO-NE in ‘Race’ to Replace Retirements.)
“If you push storage all the way … you could be in a situation where you store during off-peak so that when you have a period like that, you’ve got enough capacity available to draw the storage and you don’t have to pay those huge prices during peak; you don’t have to use those far dirtier sources of energy,” Baker said.
The Baker administration filed legislation in March to spend more than $1.4 billion on climate change measures, including proposing a Clean Peak Standard mandating that utilities use a minimum level of clean energy to supply the highest-priced peak hours, or 10% of grid hours each year.
Baker on Wednesday highlighted the state’s “combo platter” of ambitious goals to solicit 9.45 TWh per year of hydro and Class I renewables (wind, solar or energy storage) and to develop 1,600 MW of offshore wind by 2030, with contracts for the former due later this month, about the same time the state plans to announce its offshore wind selection.
The scheduling conflict overtaxed the Department of Energy Resources, delaying the offshore selection until later this spring, Baker said.
The state in December awarded nearly $20 million in grants for 26 energy storage projects as part of its Energy Storage Initiative and Advancing Commonwealth Energy Storage program, funded by the DOER through alternative compliance payments and administered by the Massachusetts Clean Energy Center.
The storage projects are also drawing an additional $32 million in matching funds pledged by developers or host municipalities, “which in my view is always the right way for us to be investing in this stuff,” Baker said. (See Massachusetts Awards $20M in Energy Storage Grants.)
ISO-NE had no storage in its interconnection queue a couple years ago. It now has more than 500 MW of grid-scale energy storage proposals in the queue, a number that has been growing even in recent weeks, said Christopher Parent, the RTO’s director of market development.
“I think that speaks highly both to state policy in the region driving interest in storage,” Parent said, “but also to the fact that storage itself is becoming a more commercially viable product and can actually participate in the market, potentially on a merchant basis as its costs continue to decline.”
Dan Finn-Foley, senior energy storage analyst for GTM Research, said “energy storage costs have dropped dramatically over the past few years” and projected the trend to continue. ESA figures show the costs for large-scale storage systems declined by 50% since 2014, and Finn-Foley estimates those costs will drop an additional 35% by 2022.
“Storage’s participation in the wholesale market depends on size, location and function — what they want to do,” Parent said.
He noted the RTO is applying the same market cost allocation exemptions to storage that are applied to pumped hydro — uplift charges, for example — and for the same reasons: the reliability services they provide to the grid.
Galen Nelson, senior director for innovation and industry support at the Massachusetts Clean Energy Center, said, “I think it’s interesting to note that two out of three offshore wind applicants included storage in their 83-C proposals, so that community is seeing storage as a key asset to improve the economic viability and attractiveness of those proposals.”
Finn-Foley said there could be a 20-GW opportunity for storage to replace costly gas-fired peaker plants.
“In California, several natural gas peaking plants that were planned have been either scrapped or they’re being re-examined, with energy storage potential taking over there,” Finn-Foley said. “In addition, in Arizona they’re putting a moratorium on new natural gas plants, focusing on energy storage instead.”
Unique Storage
Storage is unique in many ways because it can participate in markets on so many different levels, Parent said.
“Eventually you could put storage behind commercial very easily and I think that’s where it becomes unique, because if someone comes to me and says, ‘I have this great storage project, I want to participate in your markets,’ [the] first question I ask is: ‘What is your project?’” he said.
The RTO must first understand how a project wants to participate, which is a function of its size, location and purpose, Parent said.
“Some project developers come to us and they don’t even want to participate in the markets, they just want to understand how to interconnect,” Parent said. “They’re focused on demand charge savings.”
Asked about how the RTO treats solar facilities with storage capabilities, Parent said its prefers to directly meter solar.
For smaller applications, “we feel we get a much more efficient outcome by modeling those facilities discretely, so we’re dispatching and taking full advantage of the capability of the battery, and also in effect letting the solar participate in the market based on its physical characteristics,” Parent said.
“What we see is when we start bundling facilities together, our ability to efficiently dispatch that facility and count ancillary services on it actually starts to disappear,” he said.
Xcel Energy, the Mountain West Transmission Group’s largest member, said late Friday that it is withdrawing from the Rocky Mountain group and its efforts to join SPP — potentially dooming the planned integration.
Executive Vice President David Eves, group president for Xcel’s utilities, said in a press release that the company recently completed a review of the Mountain West’s proposal to join SPP and determined that “continued engagement in Mountain West is not in the best of interests of our customers or the company.”
Xcel said “limited benefits” for the company’s Colorado customers, a lack of “market expansion opportunities” for the Mountain West and increasing “uncertainty over the costs of the RTO” led to its decision.
Friday’s announcement caught SPP and Mountain West off guard. Xcel spent much of Friday alerting Mountain West members, state and federal regulators and other interested parties before issuing the release.
In an emailed statement, SPP CEO Nick Brown said the RTO was “surprised and disappointed.”
“SPP has spent significant time and effort attempting to bring organized wholesale markets and their many benefits to the West,” Brown said. “We’re hopeful there will still be opportunities to do so.”
Brown addressed the issue at the Regional State Committee meeting in Kansas City on Monday. “Obviously, we were shocked Friday by the announcement of [Xcel] pulling out of the Mountain West initiative,” he said. “In my initial discussions with other participants of Mountain West, they’re meeting to determine what their next steps are, and we will certainly do the same.”
Members of the RSC, which comprises regulators from most of the 14 states in SPP’s footprint, have also expressed reservations about the integration’s cost allocations. (See Mountain West, Cost Allocation Top SPP RSC Concerns.)
The decision left several of Mountain West’s entities pondering their next steps. With 1.4 million customers, Xcel’s Public Service Company of Colorado subsidiary represents about 40% of Mountain West’s base.
Lee Boughey, senior manager of communications and public affairs for Tri-State Generation and Transmission Association, said the cooperative would “take time to review its options and determine the best approach to move forward.”
“Ultimately, any decision to participate in a regional transmission organization will be dependent on whether it benefits our members,” Boughey said.
Tri-State is a member of both Mountain West and SPP, having joined the RTO as part of the Integrated System’s membership in 2015.
Theresa Donnelly, senior communications manager for Black Hills Corp., said her company is also “evaluating the impact” of Xcel’s departure from the SPP integration effort.
“We will continue our discussions in the coming days and weeks,” Donnelly said. “We respect Xcel Energy’s decision to end their participation in Mountain West, as the benefits and costs of RTO membership differ for each company based on their unique business situation and interests.”
Mountain West, which primarily services Colorado, Wyoming and Nebraska, began discussing RTO membership in 2013. It announced in January 2017 that it was pursuing membership in SPP, and in March, the RTO’s Board of Directors approved a set of policy recommendations intended to govern the terms of Mountain West’s membership. (See SPP Begins Work of Integrating Mountain West.)
Xcel said “a variety of interrelated items” drove the company to its decision:
The limited overall benefits to Xcel’s customers, “given the relatively small size of the MWTG footprint.”
The few opportunities for westward expansion of the RTO, “which might have added to the value proposition.”
A recent increase in the costs of forming an RTO, with “less certain” benefits that are “highly dependent on both the footprint, generation flexibility and composition of” Mountain West.
Recent developments with RTOs have “introduced an increased risk of more significant changes to state-regulated retail electric service than Xcel Energy had anticipated.”
“Xcel Energy will continue to focus on initiatives that will benefit our customers, keep bills low and facilitate the addition of renewable resources on our system,” Eves said. “Our customers and the state of Colorado benefit when states control their own energy policy.”
Colorado wind farm | Xcel Energy
Colorado’s Public Utilities Commission, which has jurisdictional authority over Xcel and Black Hills, was thought to be the primary stumbling block to completing the Mountain West’s integration. The PUC declined to comment Saturday.
Denver-based attorney Abby Briggerman, who represents consumer groups before FERC, said in a statement: “We appreciate Xcel’s efforts to ensure meaningful savings for ratepayers and hope that whatever the alternatives considered, there will be a transparent stakeholder process to allow for comprehensive consideration of the best course forward.”
The Western Area Power Administration issued a statement saying it “appreciates the strong collaborative partnerships” within Mountain West and “is assessing [its] next steps” following Xcel’s withdrawal.
“WAPA maintains its commitment to working with neighboring entities across its 15-state footprint to develop strategies to adapt to the evolving electricity industry,” said Chief Public Affairs Officer Teresa K. Waugh. “We will continue to evaluate and pursue opportunities to optimize the utilization of generation and transmission resources across multiple utility systems.”
In recent weeks, a growing number of SPP stakeholders have pushed back against the Mountain West integration. A group of five members filed a letter April 6 asking the RTO’s board to reconsider its decision to move forward with the integration until “there is more consensus within the SPP membership as to how to proceed.” (See SPP Group Balks at Mountain West Concessions.)
On Wednesday, Lincoln Electric System (LES) issued its own letter, saying it agrees with the April 6 missive that the board should reconsider the approved MWTG policy recommendations.
LES said it is concerned about the recommendation proposing regionwide cost allocation for the Mountain West DC ties. “The expectation that existing SPP members would pay for DC tie legacy facilities is unprecedented and in contravention to the SPP Tariff,” wrote LES CEO Kevin Wailes.
LES also said there is no policy justification for the proposed three-year phase-in administrative fee discount for Mountain West members. “lf the purported benefits of the [Mountain West] integration have been accurately represented, there should be no need for one subset of SPP transmission owners to subsidize another subset during this period,” Wailes said. “Like others, we are in support of efforts to strategically bring in new entities that aren’t at the unnecessary expense of SPP’s existing members,” he added.
On Friday, the Missouri Joint Municipal Electric Utility Commission and the municipal utilities of Springfield and Independence, Mo., filed a joint letter outlining their concerns in language almost identical to that of LES.
SPP’s board and its Members Committee are scheduled to meet Tuesday in Kansas City, Mo. The agenda includes a Mountain West update and a president’s report, which will likely generate much discussion.
WASHINGTON — FERC told Congress last week it is ready to act on distributed energy resources following a technical conference earlier this month, assuring House members they will not encroach on state jurisdiction.
During a hearing before the House Energy Subcommittee on April 17, commissioners said the April 10-11 technical conference on DERs had helped them answer the questions that had led them to delay action on distributed resources when they issued Order 841 on energy storage in February. (See FERC Rules to Boost Storage Role in Markets.)
Commissioner Richard Glick cited questions about DERs’ reliability and how the commission interacts with states on aggregation. “I think we got enough information [at the technical conference], in my opinion, to address the issue,” he said in response to a question from Rep. Kathy Castor (D-Fla.). (See Gatekeeper or Facilitator? FERC Panels Debate EDCs’ DER Role.)
FERC Chairman Kevin McIntyre agreed, saying “the record we are assembling in that process will enable us to take steps comparable [to the commission’s action on storage]. I’m not saying that to forecast a particular outcome. I’m just saying that we’ve got enough now to go on to make a determination about what the appropriate steps are.”
Commissioner Cheryl LaFleur said there are two “macro issues” to be determined: one financial, the other operational.
She said ensuring that DERs do not receive duplicate payments at the wholesale and retail levels “will require some very specific rules.”
LaFleur said the commission got valuable testimony on the second issue: “how the different control centers talk to each other.”
“I think one of the big issues we’re going to have to think about as a body now is how uniform we make the rules as we put them out as opposed to allowing regional variations,” she continued. “Some of the people testified about wanting different regions to go in different directions here. I’m somewhat of the belief that the technology is marching so quickly that we should try to figure out what best practices are now. That’s what we’ll be debating.”
Rep. Gregg Harper (R-Miss.) questioned whether FERC was intruding on state and local regulators. “With the issuance of Order No. 841 and its proposal for the aggregation of DERs for the purpose of participating in wholesale electric markets, FERC could expand its authority at the expense of states and localities,” he said.
“Honestly, I’m not particularly troubled by any sort of jurisdictional creep because that power would make its way onto our grid in a way that we could regulate it only after it had been aggregated and put forth to a market that we regulate — a wholesale electric market,” McIntyre responded. “And there certainly is no attempt on the part of this commission to in any way thwart the ability of the state, for example, to determine in a retail-level transaction what the owner of the generating resources — what level that owner would be compensated. Honestly, I don’t see that as being a particularly grave concern.”
The commission will likely be inviting post-technical conference comments after transcripts of the technical conference are posted.
The three-hour hearing was the first with the full commission since 2015, according to Energy and Commerce Committee Chairman Greg Walden (R-Ore.). Also discussed were the commission’s grid resilience inquiry, the financial struggles of coal and nuclear generation, the Public Utility Regulatory Policies Act and the commission’s review of its 1999 policy statement on gas pipeline licensing. (See related stories, FERC Outlines Gas Pipeline Rule Review.)
Coal and Nuke Woes
The commission’s decision to open an inquiry on grid resilience after rejecting Energy Secretary Rick Perry’s call for price supports for coal and nuclear plants came up repeatedly in questions from committee members.
Rep. Joe Barton (R-Texas) called for “regulatory relief” for struggling coal and nuclear generators, saying market changes could result in unsustainable subsidies. “The regulatory burden obviously on nuclear is very high and you can argue that it’s also very high on coal plants. If we look for solutions to keep our distressed nuclear plants and coal plants in service, we should first look at regulatory relief and only then look at market relief,” he said. He did not elaborate on what regulations should be reduced.
Rep. David McKinley (R-W.Va.) brought up the “domino effect” he said will result if the 1,300-MW Pleasants County coal-fired plant is forced to retire after FERC rejected FirstEnergy’s proposal to move it from its merchant unit to a regulated utility. FirstEnergy announced in February it would close the plant in early 2019 if no buyer is found. (See FirstEnergy Shutting down Unsold Coal Plant.)
“This is a small county. Thirty percent of the tax revenue comes from that power plant. … That’s going to affect their school system. What about their [emergency medical service]? What about their hospital? If this power plant closes down, there’s a very high likelihood that the coal producer that supplies that power plant [Murray Energy] will similarly declare bankruptcy. If [CEO Robert Murray] declares bankruptcy, his relief will be to get away from his [United Mine Workers of America] pension responsibility, which currently funds 120,000 retirees. If that’s reduced, they would be shifted over likely to the federal Pension [Benefit] Guarantee Fund. I’ve got a letter from the Pension Guarantee Fund that says, ‘Don’t put those 120,000 on us because then we’ll go under.’ So, you see the domino effect of this,” he said.
McKinley asked the commission whether it had calculated the cost to consumers of subsidizing the plant.
“I do not have that figure,” responded McIntyre.
“We have reason to believe it’s less than $50 a year per customer. The consumer currently is paying $50 a year for tree trimming,” McKinley said. “I think we have a moral responsibility to look at this thing holistically, rather than just an ideological fight [over] what we think … is a free market.”
“Would you agree? Do we have a free market system in energy?” he continued.
“We do not have a perfect market system in energy, that is certain,” McIntyre responded.
Rep. Adam Kinzinger (R-Ill.), whose district is home to four nuclear plants, said he was concerned that the loss of nuclear generation would harm resilience. McIntyre said the commission’s resilience docket (RM18-1) could result in additional revenue for nuclear plants if FERC determines they provide resilience attributes for which they are not compensated.
Commissioner Robert Powelson reminded Kinzinger of the history of Illinois’ move to retail choice. “Those nuclear plants you referenced, customers paid a competitive transition charge as part of a stranded cost investment. So here we are today in your state and my state [Pennsylvania] … where something that was quote ‘too cheap to meter’ is coming back into the market. … We’re being asked theoretically — your constituents are being asked — to do another stranded cost for those assets. So, if I’m a gas operator or I’m an emerging technology in the market, I’m not getting any type of backstop for my resource.”
Rep. Bill Johnson (R-Ohio) asked Powelson about his response to Murray’s criticism that “FERC didn’t do its job” when it rejected the Perry’s request. Responding on Twitter, Powelson initially challenged Murray to a debate, a tweet he later deleted.
“I take offense to the word ‘feckless’ being used to [describe] colleagues that I serve with here,” responded Powelson. “My colleagues and the 1,320 [FERC] employees who show up to work every day to do their job around safety and economic regulation and making sure our wholesale power markets are functioning. … I refrained from [pursuing a debate]. I thought it was inappropriate and I dialed it back rather quickly.”
Transmission Spending
Several members questioned whether FERC and RTOs were allowing unnecessary transmission spending.
Rep. Frank Pallone (D-N.J.) questioned whether Jersey Central Power & Light’s proposed $111 million Monmouth County Reliability Project is necessary to accomplish the company’s reliability goals. “Recently this view was echoed by New Jersey Administrative Law Judge Gail Cookson, who ruled that JCP&L failed to demonstrate that their transmission line is necessary and noted that JCP&L has not seriously considered alternative corridors and ignored non-transmission solutions entirely,” Pallone said, adding that the utility should have considered distributed generation, storage and new grid technologies.
“Her decision supports my long-held suspicion that often projects like this … are more about the rate of return for shareholders than reliability for consumers.”
Powelson expressed sympathy. “I have a concern when industrial customers come in to the commission as energy users telling us that they’re seeing a 400% increase in transmission costs as wholesale [energy] prices are dropping. That’s alarming. That tells me that the RTOs at the wholesale level of transmission planning are not doing a very good job of cost containment. And we are all paying for that as consumers.”
Rep. Billy Long (R-Mo.) cited complaints by the City Utilities of Springfield that it has seen a substantial increase in its transmission costs in SPP, “most … related to funding transmission projects outside of” the state.
“Some of the projects allow utilities to access renewable energy located outside of the state. However, the benefits [are] far outweighed by the rise in transmission costs,” Long said. “SPP’s own studies have shown the City Utilities’ transmission costs and energy prices are substantially higher than other customers in the Southwest Power Pool. What will FERC do to address the issue of rising transmission costs in” the RTO?
McIntyre said he was unfamiliar with the study Long referenced but agreed to investigate the matter. “Generally speaking, it would be surprising that a particular entity paying those transmission costs is paying significantly higher than other entities served by the same” RTO.
Order 1000
Glick and McIntyre, the newest members of the commission, said they want to take another look at some of FERC’s transmission policies.
McIntyre said the commission’s transmission planning rules are “something that’s ripe for evaluation as to whether it’s working as well … as was hoped for when we issued” Order 1000.
Glick said the commission should reconsider how it awards return-on-equity incentives to transmission developers.
“Are we incenting the right thing? For instance, we incent RTO participation, but a lot of … utilities are participating in RTOs regardless of whether they have an incentive or not,” Glick said. “We really should be incenting, ‘Are we using transmission capacity more efficiently? Are we using new technologies to make transmission capacity more efficient?’ Those are the kinds of things that I think congress gave us the authority to do.”
Rep. Tim Walberg (R-Mich.) pressed the commission to revise its enforcement of PURPA, noting it has been nearly two years since the commission’s technical conference on the subject. (See FERC Conference Debates PURPA Costs, Purchase Obligations.)
McIntyre said an overhaul of the law would be up to Congress but said FERC can act to prevent abuses of its 1-mile rule and 20-MW threshold. “I think the record is already there to act on the 1-mile rule,” agreed Commissioner Neil Chatterjee. He added it “could be a challenge” to get a bill through Congress.
‘By Operation of Law’
Rep. Joseph Kennedy (D-Mass.) used his time to urge support for a bill he is sponsoring to address the commission’s 2-2 deadlock in September 2014 over whether it should reject the results of ISO-NE’s eighth Forward Capacity Auction because of unchecked market power. The 2017-18 auction results became “effective by operation of law” (ER14-1409). Under the FPA, rates take effect 60 days after they are filed with FERC, absent a commission order to the contrary.
