VALLEY FORGE, Pa. — After months of debate in several transmission planning venues, PJM has begun discussing the role and significance of cost-containment assurances in bids for transmission projects under FERC’s Order 1000.
The debate has elicited frustration both from merchant transmission developers, who feel they should receive a competitive edge for sticking to a budget, and representatives of load, who say there is currently little incentive for developers to carefully count pennies in their estimates. A special session of PJM’s Planning Committee has held two meetings on the issue, the second of which last week focused on how cost-containment could be factored into the RTO’s planning.
Craig Glazer, PJM vice president of federal government policy, described a proposed four-stage cost cap review process — which includes examining cap provisions during project submission, evaluation, approval and construction — and outlined potential implementation issues. He preceded the discussion with a round of “Who Does What?” — a fictional gameshow he’s used before to highlight a lack of clear jurisdiction on transmission issues. (See Who Decides? Panel Highlights Blurred Jurisdiction on Tx.)
The submission process needs to include rationale for any exclusions to the cap in order to avoid “an exclusion so big it effectively makes the cost cap meaningless,” but also provides for confidentiality, he said.
“If you start exposing every element of the cost cap [publicly], all you’re doing is telegraphing to vendors how much you’re willing to pay for that portion of the project,” he said.
PJM’s “tentative view at this point” is to limit cost caps to construction costs that would include the internal cost of capital to finance the project, which is the “where the competition is” between proposals, he said.
| PJM
“If somebody wants to submit … a life-of-the-asset project construction cost, we’re not going to consider that,” he said. “You can present that at FERC as part of your rate filing, but … don’t file it here.”
Transource Energy’s Dan Rogier agreed that any cost cap should focus on construction. “Those aspects of a project that are harder to track over time … should carry less weight than things that are known from a construction standpoint,” he said.
Another issue, Glazer said, is identifying who enforces the cap once it’s approved. PJM is not a regulatory agency, he said, so if it is put in charge, “we’re in this odd position of calling balls and strikes … for load,” he said. “I’m effectively the construction manager.”
He also made it clear that cost caps are just one component — and not the most important one — of PJM’s selection criteria and should be voluntary.
“You can’t make someone file a cost cap,” he said.
Representatives from several transmission owners, including Transource, ITC Mid-Atlantic Development, Duquesne Light and LS Power, agreed that cost caps should be voluntary.
However, LS Power’s Sharon Segner urged PJM to be more proactive.
“We think, from a PJM perspective, that this is a good development,” she said. “We think that cost caps should also be encouraged … because risks are being transferred and that has the potential to bring consumer benefits.”
The “main role” for PJM, she said, is to select the most cost-efficient, cost-effective project.
John Farber of the Delaware Public Service Commission said cost caps are not a “panacea,” but that the discussion is important for addressing a larger issue.
“There’s very little ammunition that customers have [today] to argue as to whether or not costs are reasonable to be recovered,” he said. “I think that’s a lot of the frustration that’s driving this. … Basically, in my personal view, the status quo is not working.”
Several transmission representatives, including Brenda Prokop of ITC and Tonja Wicks with Duquesne, agreed that PJM doesn’t have to use the same process as other RTOs, which have given significant weight to cost caps.
“We think that PJM has the right view on this. We don’t think that SPP and MISO have the right view on this,” Prokop said.
“I think to some extent we have a blank sheet to say to FERC what we want their role to be — and ours,” Glazer said.
Hydro-Québec and several partners on Thursday submitted six separate proposals to meet Massachusetts’ call for 9.45 TWh a year of renewable generation, with one proposal alone meeting nearly the entire energy requirement.
The solicitation is a collaborative effort by the Massachusetts Department of Energy Resources and the state’s distribution utilities: Eversource Energy, National Grid and Unitil. Projects will be selected next January, with contracts to be submitted in late April.
Hydro-Québec partnered separately with Eversource, Avangrid and TDI New England on three different transmission projects, and has agreements with Boralex and Gaz Métro to add wind power into the energy mix on each project at the state’s request.
Massachusetts last year enacted a law that requires the state to contract for 1,200 MW of renewable energy, including hydro, onshore wind and solar. A separate clause in the Act to Promote Energy Diversity mandates solicitations for at least 1,600 MW of offshore wind by Dec. 20, with projects to be selected next April and contracts to be submitted at the end of July 2018. (See Offshore Wind Developers Ponder Tx Options.)
Deep Competition
Nova Scotia-based Emera proposed the Atlantic Link project, a 375-mile submarine HVDC transmission line extending from New Brunswick to Plymouth, Mass., near the retiring Pilgrim nuclear plant and close to the Boston load center. The project would become operational in December 2022 and deliver 5.69 TWh of clean energy per year to Massachusetts at a fixed price for 20 years. Energy prices were not disclosed for any of the projects.
| Emera Energy
National Grid partnered with Citizens Energy on two proposed projects. The Granite State Power Link, a 59-mile, 345-kV, HVDC transmission line from northern Vermont to New Hampshire, would deliver 1,200 MW of new wind power from Canada. The companies’ Northeast Renewable Link is a 23-mile AC line from Nassau, N.Y., to Hinsdale, Mass., designed to deliver 600 MW of new wind, solar and small hydro into the New England grid.
Granite State Power Link route map | Granite State Power Link
Important Opportunity
Eversource has partnered with Hydro-Québec on Northern Pass, a 192-mile line that would carry 1,090 MW of hydropower to New England — up to 9.4 TWh per year for a period of 20 years starting in December 2020.
“We’re confident we can deliver up to 9.4 TWh annually … we feel ours is a very strong proposal,” Eversource spokesman Martin Murray told RTO Insider. “It delivers the clean energy that is being sought, and it will be able to do that about two years earlier than any other project that’s been proposed.”
Hydro-Québec spokeswoman Lynn St. Laurent said, “In terms of our export markets, there is this very important opportunity in Massachusetts, and it’s happening now. We’re talking about an approximately 1,000-MW transmission line providing a minimum of 8.3 TWh to Massachusetts. It can go higher than that but we’re leaving some room. In some cases, we know Massachusetts wants to potentially add some smaller projects into the supply.”
Avangrid submitted several proposals Thursday, some wholly owned by the company and others joint partnerships, but it did not release a list. Its subsidiary, Central Maine Power, is partnered with Hydro-Québec on the New England Clean Energy Connect, a 145-mile, 320-kV HVDC line that would carry 1,200 MW of hydro and wind energy from Canada to Maine.
Avangrid CEO James P. Torgerson told analysts last week that his company plans to bid multiple transmission and renewable solutions into the solicitation. “They’re looking for incremental hydro on a firm basis but also new Class I renewable portfolio standard, which would be wind and solar. A combination of both could include transmission projects under a FERC tariff,” he said.
Hydro-Québec has also linked up with TDI New England on the New England Clean Power Link, a 154-mile underwater and underground transmission line that would transmit 1,000 MW of Canadian hydropower under Lake Champlain to Vermont.
[Editor’s Note: An earlier version of the article incorrectly stated that Emera is a Maine-based company. The company does have a Maine-based affiliate.]
MISO must fully consider the special attributes of energy storage devices before developing new rules that enable those resources to participate in the RTO’s wholesale markets, stakeholders said this week.
Stakeholders participating at a July 24 Common Issues workshop asked MISO to recognize the ability of storage to postpone transmission upgrades, classify prospective storage projects under a new study process, and create specific compensation rules and modeling procedures for the technology.
And participants had another piece of advice: Be prepared to change the rules as storage technology advances.
Workshop leader Carolyn Wetterlin of Xcel Energy said the workshop would not directly produce policy decisions but was rather intended to gather ideas on integrating storage into MISO markets. She said the RTO would plan a follow-up meeting for Aug. 24 to decide which stakeholder committees would take up energy storage issues.
Storage as a Transmission Solution
Entergy’s Ayesha Bari said battery storage should not be treated purely as a generation resource because it can respond more quickly than a generator and does not depend on fuel sources. Batteries are more akin to transmission assets because they do not produce power but provide “time-shifted load consumption on the electric grid,” she said. They can also be recommissioned for use at other problem sites after helping to defer a transmission project as long as possible.
Invenergy Director of Regulatory Affairs John Fernandes agreed with the principle of using storage to defer transmission and distribution system upgrades. He offered the example of installing a battery to equip a 100-MW substation to handle a 125-MW peak load, with charge gathered when load is less than 100 MW to in order to handle the extra 25 MW during peak intervals. He also asked for rules that would monetize such use.
“If we can firm up the opportunity and how this looks in MISO, we’ll get a lot more proposals,” Fernandes said. “I’m not sitting here asking for a handout for energy storage; I’m talking about optimizing the grid.”
Fernandes said MISO must specifically address the instances when a storage resource is required to remove itself from market participation in order to recharge. “In some places, they call that not following your set point, and that’s frowned upon,” he said to laughter from stakeholders.
“I think a product definition and market rules could assist modeling. What are your thoughts on that?” Customized Energy Solutions’ David Sapper asked.
“I think there needs to be a good bit more certainty on development rules and processes before robust projects are brought forward,” Fernandes replied.
Entergy’s Yarrow Etheredge said that MISO’s annual Transmission Expansion Plan — rather than the RTO’s interconnection queue — is the more appropriate forum for considering the use of storage based on its potential benefits to the system, which could require specific studies.
“You’re not looking at the right things in the generator interconnection process,” she said.
Jason Burwen, policy director with the Energy Storage Association, joined the chorus, saying storage can also defer transmission upgrades by relieving congestion. Batteries can also provide several uses beyond ancillary services, including “grid balancing, backup, system capacity, network capacity, curtailment avoidance and energy arbitrage.” He said MISO’s “lack of clear market mechanisms” fails to monetize storage benefits.
“The main barrier to storage is lack of an effective means to value and compensate it for its capabilities,” Burwen said. “If we can modernize the Tariff, operating and planning structures, we expect that they can compete on their own merits.”
Fernandes introduced a concept he dubbed “smoothing with storage,” in which storage can flatten renewable output spikes by providing firm output over a one-hour time block. Xcel’s Beth Chacon added that storage technology can temper rapid solar ramping rates.
Lorenzo Kristov, an adviser on market and infrastructure policy at CAISO, said the future grid may be an “integrated decentralized system” in which the RTO manages several local distribution areas comprised of microgrids, a departure from a central transmission system that delivers energy across hundreds of miles.
Kristov said energy storage market integration requires complementary strategies, which include valuing storage’s services and not just the delivered electricity, laying out “storage-as-demand response” rules and creating procedures for either resource owners or RTOs to manage a battery’s state of charge and set maximum charge and discharge rates.
“There really aren’t well-defined services that these storage resources can be compensated for,” Kristov added.
Ludington pumped storage facility | Consumers Energy
DTE Energy’s Nicholas Griffin said his company’s pumped storage facility in Ludington, Mich., currently offers into the market one day at a time through an energy limited resource offer based on the company’s own optimization to determine the amount bid into the market. About 10 hours of pumping at the Ludington station yields about eight hours of generation for the 1,872-MW facility.
Griffin said DTE would like MISO to model storage assets as both generation and load sources in market and planning processes and optimize generation and load cycles as far as 10 days in advance. The RTO should also learn to “better leverage a flexible source or sink of energy for operational or reliability reasons,” Griffin said.
“We want MISO to fully leverage existing assets while enhancing the market to accommodate new ones,” he added. “All these resources are different, and we need to figure out to properly and adequately compensate them for services that are needed.”
“If you want to talk batteries, well, I guess I have a huge battery at Lake Winnipeg,” said Manitoba Hydro’s Audrey Penner, noting the company has pumped hydro storage capability between 2 and 10 TWh. Penner said she “strongly disagrees” with limiting a MISO storage definition to either a battery definition or four-hour storage capabilities.
Burwen said that several megawatt-scale storage facilities are nearing a decade of operations across the nation and said that technological advances in storage capability, including flow batteries using electrolyte liquid and flywheel mechanical storage, are driving a surge in new projects.
“You’re opening up a very wide range of possibilities,” he said. “Utility and transmission owners, customers and third parties are all operating battery storage.”
The cost of lithium ion batteries — the nation’s dominant storage technology — have decreased from about $1,000/kWh in 2010 to $273/kWh in 2016.
“Costs of battery storage have been declining very rapidly,” Burwen said. “Battery storage generally tops out at four hours, but I think that’s a matter of cost. You’re going to see potentially longer duration assets as those costs go down.” By 2020, developers are expected to add about 3,900 MWh of storage on an annual basis in the U.S., Burwen said, citing projections from the ESA.
‘No One-Size-Fits-All’
“It could change how we use energy,” said MISO Director of Market Research and Development Jessica Harrison, adding that the RTO continues to mull storage definitions.
“We want to work quickly, but we don’t want to move too quickly. We don’t want to pin ourselves in a corner” by getting storage rules and definitions out too soon, she said.
“There is absolutely no one-size-fits-all solution for this area,” MISO External Affairs Policy Advisor Jennifer Richardson said.
MISO took a stab at one solution earlier this year in a FERC compliance filing responding to a complaint by Indianapolis Power and Light over compensation for a 20-MW battery at the utility’s Harding Street Station. (See MISO Ordered to Change Storage Rules Following IPL Complaint.) The RTO proposed to create a new resource category — Stored Energy Resource–Type II — that would not be limited to providing regulation services (ER17-1376). Instead, it would be required to function largely as a DR resource, except that it would be treated as a regular generation resource for settlements, and would not be eligible for revenue sufficiency guarantee or day-ahead margin assurance payments.
Richardson said that while MISO generally agrees with FERC’s Notice of Proposed Rulemaking requiring RTOs to remove market barriers for storage and distributed energy resources, it also believes the two types of resources should be considered separately. (See FERC Rule Would Boost Energy Storage, DER.)
MISO thinks that “prescriptive measures for DERs aren’t as ripe,” Richardson said, adding that the RTO must collect more data on how DERs behave in other markets before it creates its own rules.
Fernandes cautioned MISO against taking too much time to craft storage rules, noting that the discussion has already gone on for over a year.
“I guarantee whatever rules are put in place for storage will have to be changed frequently,” he said. “If [it takes too much time] to get revenues in place, we’re going to go somewhere else.”
“We expect this to be a continuing process. We don’t expect to have one response and call it a day,” Harrison said.
“The worst thing that I think can happen is we do nothing and we receive very specific FERC guidance on a tight timeline,” Richardson said.
Critics are pushing back on a plan by Upper Michigan Energy Resources Corp. (UMERC) to build two natural gas-fired generators in Michigan’s Upper Peninsula, claiming that the company hasn’t adequately justified the need for them.
The Michigan Public Service Commission last year approved a settlement to create UMERC, which consists of the electric and gas distribution assets of Wisconsin Electric Power Co. and Wisconsin Public Service, both subsidiaries of Milwaukee-based WEC Energy Group. (See Michigan Upper Peninsula Getting its Own Utility.) The company earlier this year filed for a certificate of necessity to build two reciprocating internal combustion engines — at a combined 183 MW — to replace We Energies’ 431-MW coal-fired Presque Isle Power Plant (18224).
Presque Isle power plant | WEPCo
The PSC is expected to decide on the application in the fall. If approved, construction would begin early next year, with the plants expected to be in service by 2020.
But the company’s $277 million plan is now a target of criticism from multiple organizations that charge that the application was not well thought out.
‘Closed-Door Negotiations’
The Chicago-based Environmental Law and Policy Center (ELPC) contends that the gas-fired projects are the result of “closed-door negotiations” between UMERC and Tilden Mining, owner of a local iron mine and the largest future customer of the proposed plants.
| UMERC
In a mid-July brief asking the Michigan PSC to reject UMERC’s application, ELPC argued that the company flouted an official PSC process that requires developers to first study renewable alternatives to fossil fuel-based projects, and instead prematurely agreed to Tilden’s request for natural gas generation — and no other technology — in a special contract.
“Prior to signing the contract, no analysis was done by WEC to determine whether [reciprocating internal combustion engine] technology was the most reasonable and prudent means of supplying electricity in what would become the UMERC service territory in Michigan’s Upper Peninsula,” ELPC said.
“Even though ELPC fully supports the closure of the Presque Isle Power Plant, we’re concerned about the process here. In order to pass the cost of the proposed gas units on to its customers, UMERC has to look into several things and one of them is the partial displacement of the proposed generation through renewables,” ELPC senior staff attorney Margrethe Kearney told RTO Insider.
proposed generation concept design | UMERC
According to Kearney, UMERC only studied a single-source scenario in which renewables met 100% of the need in the Upper Peninsula.
“I don’t think anybody at this point thinks that renewables will cover all of the needs [in the area],” Kearney said. “That’s what flagged our concern. We said, ‘Wow, they didn’t really look into this.’”
When UMERC did factor renewables into its plan, the company neglected to reduce a corresponding amount of capacity from the proposed gas-fired plants, making the renewables appear costly and unnecessary, Kearney said.
“I find it troubling that they wouldn’t go back on whatever project they agreed on with the mine and consider replacement of some of the gas units with renewables. They did it out of order,” she said.
Kearney also worries that UMERC may be overlooking renewables to the detriment of its customers.
“The amount that they’re building is pretty significant,” she said. “It’s more capacity than what they need. I don’t think there’s any question that they’re not going to need to build anything for a long time. But they’re not looking at five years ahead when the cost of storage and renewables drops.”
While Kearney said she understands that energy is expensive in the Upper Peninsula, her organization wants to ensure that the region’s energy “is crafted with all of the factors in mind.”
“I can’t say that this is the best option for the rest of the customers. The only stakeholder involved in the process was the mine. The goal is not to accuse them of a nefarious plot, but it really calls into question the legitimacy and credibility of the proposal,” she said.
UMERC’s Defense
UMERC stands by its filed proposal.
“We believe our proposal will provide a long-term, low-cost source of electric power to the Upper Peninsula,” WEC spokeswoman Amy Jahns said.
UMERC considered multiple renewable supply options for the Upper Peninsula, but they weren’t the best fit for the region, according to Jahns.
“Those options were found not to be a low-cost and reliable source of power. Wind and solar energy options are limited to generating or producing intermittent power that would not meet the need of our customers. In addition, advances in battery storage technology do not meet the need for this project,” she said.
The Marquette County Board of Commissioners penned a resolution in support of UMERC’s plans, claiming the “environmental benefits of the new generating solutions will greatly reduce regional air emission and will negate the need for the development of costly major transmission lines.”
Overbuilding?
Nearby Cloverland Electric Cooperative also asked the PSC to deny the certificate of necessity, saying that UMERC “insufficiently addressed a number of issues contained in its application.”
Cloverland contends that UMERC is overbuilding capacity in relation to need in the area, and that the proposed plants may cause congestion on the local transmission system, forcing the cooperative to pay system reliability, voltage or local reliability payments to MISO. It also asked the PSC to shield it from such payments.
“Since transmission is an alternative to UMERC’s proposal and transmission would not create the cost risks for Cloverland that the [proposed] facilities do, Cloverland would have no objection to the commission conditioning the relief in this case on UMERC holding Cloverland harmless from the cost risks UMERC’s choices have created,” the cooperative said in a brief with the PSC.
In its application for the certificate, UMERC said its integrated resource plan demonstrated that the projects were needed only to replace Presque Isle and would not result in “wasteful duplication of facilities.” The company also said that the two plants are the “most reasonable and prudent alternative under the alternate scenarios analyzed,” including new transmission or upgraded transmission, new renewable sources and energy efficiency programs.
Cloverland also finds fault with the “extensive analysis” UMERC claimed it performed under its IRP.
“UMERC’s integrated resource plan failed to consider a number of potential solutions that could have potentially led to results that would be more beneficial and more efficient to the entire Upper Peninsula. The integrated resource plan provided by UMERC is nowhere near comprehensive enough for this commission to grant the relief requested,” Cloverland wrote.
Michigan Technological University also intervened in the case, claiming that as an interruptible gas customer, “the availability and reliability” of its gas supply may become compromised by possible gas capacity constraints introduced by the two new plants.
“The Northern Natural Gas Pipeline is already capacity constrained during peak demand periods. And without adequate safeguards in place, the addition of UMERC’s … electric generation facilities will only further constrain the natural gas capacity in the Upper Peninsula,” the university said, asking the PSC to condition UMERC’s certificate on the “adequate supply of natural gas” for all customers served by the Northern Natural Gas Pipeline.
Jahns said that UMERC has “received no evidence that our project will adversely impact” the university.
MISO’s system operated as intended in June, which saw the usual early summer increase in loads, lower-than-expected natural gas prices and near-normal temperatures.
The RTO on June 13 hit a 111-GW peak for the month, 1 GW under the June 2016 peak, MISO Vice President of System Operations Todd Ramey reported during a July 25 Informational Forum. Average load was about 80 GW, up 10 GW compared with May and an expected outcome of the transition into summer, he said.
The increase in load was offset by the return of about 21 GW of generation from spring maintenance outages.
Prices averaged $29/MWh in the day-ahead market and $28.13/MWh in real time, lower than in May, where average prices for both hovered around $30/MWh. The small reduction resulted from natural gas prices averages staying below $3/MMBtu, a 7% decline from the prior month, Ramey said.
| MISO
Two events caused real-time prices to deviate sharply above the day-ahead during the month, including a forced transmission outage in Louisiana on June 19 and a June 23 “contingency-related” event affecting the entire system.
While conditions in June were largely in line with norms, the MISO footprint experienced stresses from a mid-July heatwave that likely affected price and load, which will be reflected in the RTO’s July operations report, due out later this month.
“We just came off a week where parts of the footprint experienced some pretty extreme conditions,” CEO John Bear said.
Bear commended MISO control room staff and generation operators for successfully managing the high summer heat. He attributed smooth operations to the training and skill of operators.
Indianapolis Power and Light’s Lin Franks asked if MISO is considering turning to a dual-peak model using separate winter and summer dual peaks. The RTO currently models its peak using only summertime conditions.
“We have seen a narrowing of the gap between the summer peak and the winter peak,” Ramey said. “We observed that a couple of years ago in the polar vortex” and continue to see it, he said, adding that MISO staff may consider modeling the separate peaks.
The PJM Board of Managers on Wednesday approved about $417 million in reliability-related transmission projects, more than half of which will go to Public Service Electric and Gas to replace a substation in downtown Newark, N.J.
Newark Switch property exterior | PJM
“The board’s approval of these projects reinforces both PJM’s fundamental mission of preserving reliability and the value of PJM’s independent assessment of transmission needs,” CEO Andy Ott said. “Planning is evolving in PJM to consider impacts of new trends. However, studying and planning for reliability remains the top priority.”
The PSE&G substation rebuild is expected to cost ratepayers $275 million. A new gas-insulated substation will be built adjacent to the existing station, which will be torn down. (See “New Proposal Shaves $78M from PSE&G Switch Fix,” PJM Planning Committee and TEAC Briefs.)
Newark Switch property interior | PJM
The board also approved projects for American Electric Power, Dominion Energy, Atlantic City Electric, PECO Energy, Pennsylvania Electric, American Transmission Systems Inc., East Kentucky Power Cooperative, Exelon Generation and Dayton Power & Light. Most projects are estimated to cost less than $5 million, but a 31-mile reconstruction of a 230-kV line in Dominion’s territory is expected to run $31 million. Two ATSI reconductor projects are estimated at a combined $33.43 million.
NextEra Energy CEO Jim Robo said Wednesday that the Florida-based company would “vigorously” pursue a $275 million termination fee it says it is owed following a failed attempt to acquire Texas utility Oncor.
The Public Utility Commission of Texas in April ruled that NextEra’s $18.7 billion acquisition of the state’s largest utility wasn’t in the public interest, and then rejected two subsequent rehearing requests. Warren Buffet’s Berkshire Hathaway Energy has since announced it has reached an agreement to buy Oncor’s parent, bankrupt Energy Future Holdings (EFH), which would give it control of Texas’ largest utility. (See PUCT Staff Welcomes Buffett’s Oncor Bid; Debtor Miffed.)
During a conference call with financial analysts following the company’s release of second-quarter earnings, Robo said the termination fee was triggered when NextEra was unable to agree to a list of what it called “burdensome conditions,” which included protective ring-fencing around Oncor and an independent board of directors for the company.
“The agreement has been terminated by EFH … in that the burdensome conditions had not been satisfied, which was one of the precursors to obtaining regulatory approval,” Robo said. “As a result of the termination of merger agreement, we will vigorously pursue our rights to termination of the fee.”
NextEra has also filed a lawsuit in Texas state court against the PUC, asking the court to reverse the regulators’ rejection of the proposed acquisition. Robo declined to address the lawsuit, saying the petition it filed “speaks for itself.” (See “NextEra Sues over Regulators’ Rejection of Oncor Acquisition,” Company Briefs.)
Asked about the Department of Energy’s grid reliability study and its focus on baseload power, Robo said it was too early to speculate about the final report’s conclusions. He said the “data is pretty clear” that the grid does not have any reliability issues.
“The facts are, the grid is very reliable in America right now, particularly as storage prices come down and make renewables more reliable,” he said. “Our industry has a choice of hanging on to the techs of the past or adopting and embracing the technology of the future. We know what our strategy is. We’re going to embrace renewables and embrace them hard.”
NextEra reported an 11% increase in adjusted earnings during the second quarter, from $777 million last year to $881 million this year. Earnings per share were $1.86, up from $1.67, beating Nasdaq’s consensus analysts’ forecast of $1.76.
The company’s stock price jumped almost 2%, from $142.62/share to $145.35/share, after the market opened. It was trading at $144.94/share by late afternoon.
WASHINGTON — RTO officials acknowledged Wednesday that they are challenged by low power prices and a shifting generation mix but insisted they are up to the task, asking Congress not to abandon its support of wholesale markets.
“Although debate on various market rules is perfectly appropriate, we caution against the potential to add greater uncertainty to the markets by signaling some kind of wholesale retreat from the competitive market model that has been in place since the mid-1990s and has worked well to keep prices low and investment certain,” Craig Glazer, PJM’s vice president of federal government policy, told the House Energy and Commerce Committee’s Subcommittee on Energy.
“The markets are working very well,” agreed SPP CEO Nick Brown, who said his RTO provides net benefits of more than $1.7 billion annually — a benefit-cost ratio of 11:1, he said. MISO provided $3 billion in benefits last year and $18 billion over the last decade, said Chief Operations Officer Richard Doying.
Representatives from all six FERC-regulated RTOs and ISOs appeared along with an ERCOT executive at the nearly two-and-a-half hour hearing, the third in a series of fact-finding sessions that began last year with a letter to FERC and a hearing in September on the 1935 Federal Power Act. On July 18, the committee heard from stakeholders representing public power, independent power producers and integrated utilities. (See Public Power Takes PJM Gripes to Congress.)
A Republican committee aide, speaking on background, said the bipartisan hearings will resume after the August recess. Although some witnesses and committee members at last week’s hearing called for changes to the 1978 Public Utility Regulatory Policies Act, “consistently what we’ve heard is that there’s no immediate need” for changes in the FPA, the aide said.
The aide said, however, that the May 1-2 FERC technical conference on tensions between wholesale markets and out-of-market procurements and subsidies “got more attention [from House members] than any other technical conference in recent history.”
Criticism Nothing New
As at the technical conference and the July 18 House hearing, much of the focus was on PJM, NYISO and ISO-NE, the three eastern grid operators facing the most acute challenges from state policies.
PJM has perhaps the toughest challenge of the three grids in threading the needle between stakeholders pushing for supports for coal and nuclear “baseload” power and efforts to insulate the markets from price suppression. Unlike the single-state NYISO and the environmentally activist New England states, PJM’s footprint is particularly diverse, encompassing both consumer choice states and traditional, vertically integrated states; only some states have renewable portfolio standards; some states are coal producers, while others are heavily reliant on nuclear power.
But Glazer, a former Ohio utility regulator and PJM’s longtime voice in D.C., said the conflicts are nothing new for the RTO. “The PJM markets have weathered many challenges to the industry, ranging from the impact of EPA’s Mercury and Air Toxics rule on the coal fleet to the threats of cyberattacks on the grid itself. We are stronger as a result and are confident that innovative market-based solutions, which have been the hallmark of PJM since its inception, can continue to serve us well in addressing our new set of 21st century challenges.”
He appealed to his congressional inquisitors by holding up photos of new generation in several of the committee members’ districts.
On several occasions, he attempted to rebut criticism by public power providers who say their self-supply option has been eroded since the settlement that created PJM’s capacity construct. Lisa McAlister, senior vice president and general counsel of regulatory affairs for American Municipal Power, told the committee July 18 that PJM rule changes “have stripped away guaranteed clearing for self-supply.”
Glazer cited 1,375 MW of new generation or uprates to existing public power-owned generation since the inception of the capacity market. The RTO has added more than 46.5 GW of new generation over the same period.
The order “did not overturn the specific agreed-to arrangement that PJM and its stakeholders worked out with public power entities,” Glazer said. “As a result, the right to self-supply in our capacity market and energy market has been negotiated with public power and fully honored by PJM and its stakeholders. To suggest otherwise is simply not consistent with those facts.”
“Absolutely, we have self-supply today,” Glazer reiterated in response to a question from Rep. John Shimkus (R-Ill.). “We have no intention of changing that.”
But Glazer rejected public power’s call to abandon the capacity market and use bilateral contracts to fill most of its capacity needs, saying it would eliminate price transparency.
Glazer had an exchange with Rep. Morgan Griffith (R-Va.), who complained that coal-fired generation was “under severe assault.” Glazer said PJM’s proposal that FERC change its price formation rules “to better recognize the attributes that key generators — including those which have come to be labeled ‘baseload generation’ — bring to the grid” would provide financial help for struggling coal plants. He said the proposed changes would “ensure that all resources needed to serve load are able to set wholesale prices.”
But he rejected Griffith’s claim that stranded costs resulting from premature coal plant retirements were falling on ratepayers. “We moved to the markets to try to not put it all on the backs of the customer,” he said.
Ranking member Frank Pallone (D-N.J.) took PJM to task for what he called excessive transmission spending and a lack of transparency in the RTO’s Regional Transmission Expansion Plan. Glazer noted that the Transmission Expansion Advisory Committee meetings are open to the public and sought to distinguish PJM’s role from that of state siting authorities. “Maybe we need to do more to reach out,” he offered.
ISO-NE CEO Gordon van Welie recalled his testimony before the committee in March 2013, when he cited the “serious operational challenges” facing New England because of its changing generation mix.
“As New England has increased its reliance on natural gas [since 2013], we have not seen a corresponding increase in the region’s natural gas transportation and storage infrastructure, which is currently stressed to meet demand for natural gas for both home heating and power generation during the coldest weeks of the year,” he said. “The shift from power plants with on-site fuel supply (e.g., oil, coal and nuclear) to plants relying on the natural gas transportation network to deliver fuel when needed has exposed the limitations of New England’s fuel infrastructure system and highlights the challenge of securing fuel in advance of power system demands.”
Van Welie said the RTO has concluded that the Pay-for-Performance capacity incentives developed in 2013 “may not be sufficient to ensure fuel security during the winter” because of opposition to siting dual-fuel facilities and tighter emission limits that restrict the amount of time generators can operate on oil. That, he said “is likely to create greater dependency” on LNG imports.
NYISO CEO Brad Jones briefed members on the ISO’s proposed transmission expansions to connect upstate renewables to downstate loads and its plan to incorporate carbon prices in its energy market — a response to the zero-emission credits approved for three upstate nuclear plants. (See New York ZEC Suit Dismissed.)
The ISO said it expects to release The Brattle Group’s report on the carbon plan within two weeks. That, Jones said, will be the basis for discussions with market participants and state officials. He said the ISO hopes to implement the plan in the markets within three years.
Unlike the other grid operators, ERCOT is still seeing strong load growth, said Chief Operating Officer Cheryl Mele. After growing at 2% annually in recent years, ERCOT expects annual growth of 1.5% for the next five years.
One thing it does have in common with the other regions: Low energy prices are pinching the finances of thermal and nuclear units. “We also have seen that, for several years, investors and unit owners of every type of generation were watching to see if there would be federal environmental policies that would materially affect their investments or retirement strategies,” Mele said. “That conversation has since changed. Nevertheless, aside from regulatory concerns, ongoing changes in the generation resource mix and market dynamics may have major impacts on potential unit retirement decisions.”
Keith Casey, CAISO’s vice president of market and infrastructure development, told the committee the effects of low power prices — which have sparked calls for nuclear and coal subsidies in the eastern markets — also have led “conventional” plants in California to request “backstop” contracts to maintain their financial viability. (See CAISO Stakeholders Question Risk-of-Retirement Initiative.)
Casey, too, defended the markets. “We have almost 20 years of operating experience and have evolved our markets since the Western Energy Crisis occurred 17 years ago,” he said. “Consequently, the California ISO’s electricity markets have matured significantly and are in far better shape now than they were then to serve electric demand in an efficient and reliable manner. Indeed, our success has encouraged other transmission providers in the West to join our real-time energy market and form the Western Energy Imbalance Market.”
Connecticut Gov. Dannel Malloy on Tuesday ordered state regulators to assess the economic viability of the Millstone nuclear power plant and determine whether the state should provide it financial support. Millstone supplies about half of Connecticut’s electricity.
The Connecticut General Assembly in June failed to pass a bill that would have allowed the 2,111-MW nuclear plant in Waterford to bid into the state procurement process (S.B. 106). Millstone owner Dominion Energy had sought the legislation to boost the plant’s revenues, which have suffered from low-priced natural gas. Gas-fired generators often set LMPs in New England.
Malloy’s executive order also directs the state Department of Energy and Environmental Protection and the Public Utilities Regulatory Authority to assess the role of large-scale hydropower, demand-reduction measures, energy storage and emissions-free renewable energy in helping Connecticut meet its ambitious targets to cut its carbon output.
The state’s Global Warming Solutions Act of 2008 mandates cutting greenhouse gas emissions to 10% below 1990 levels by 2020, and to 80% below 2001 levels by 2050.
Show us the Books
The governor’s July 25 order directed DEEP and PURA to use “the best available information, including such facilities’ audited financial statements and such other financial data that is reasonably requested by [regulators]” in their economic analysis of Millstone.
Matt Fossen, spokesman for the Stop the Millstone Payout coalition, said “it is essential that Dominion fully disclose the plant-level financials of Millstone; otherwise the investigation won’t be truly comprehensive or accurate.”
The coalition — sponsored by competitors Calpine, Dynegy and NRG Energy and the Electric Power Supply Association (EPSA) — had argued S.B. 106 would be a burden on ratepayers and an unnecessary handout to a power plant that had not been proven to be unprofitable.
The group in April released a study by energy consultancy Energyzt that showed the Millstone plant has earned at least $3 billion in profits since Dominion bought it in 2001 and will likely earn an additional $2.2 billion in after-tax income from now through 2030. Dominion spokesman Ken Holt criticized the Energyzt report as “loaded with gross assumptions and preposterous claims, with no real data.” (See Millstone No Dead Weight for Dominion, Says Opponents’ Study.)
New York ZEC Suit Dismissed
The legislation would have made Millstone the only eligible nuclear generator in Connecticut’s competitive bidding process and awarded it a five-year contract if it bid lower than competing renewable resources. The bill would have set an annual limit on nuclear energy purchases at 8.3 million MWh, equivalent to half of Millstone’s output.
The Connecticut measure would have been similar in effect to the zero-emission credit programs that EPSA and its members are contesting in New York and Illinois.
EPSA and its members in Illinois on July 17 filed an appeal with the 7th U.S. Circuit Court of Appeals. They argued they stood to lose millions because the subsidized nuclear plants would suppress capacity and energy prices. The plaintiffs are expected to also appeal the New York decision to the 2nd Circuit.
PJM’s Independent Market Monitor last week filed a complaint with FERC requesting fast-track revocation of the RTO’s decision to exempt a generator from a rule meant to combat market manipulation.
The complaint said PJM was “incorrect” in providing an unnamed generating unit with a competitive-entry exemption from the minimum offer price rule (MOPR).
The RTO developed the MOPR to prevent subsidized units from suppressing market prices by offering bids that are below a unit’s competitive operational costs. The rule creates a price floor at which all new units must offer into the market unless they receive one of three types of exemptions from PJM. The competitive-entry exemption allows a unit to offer in at any bid, provided the generator can prove it receives no direct or indirect subsidies. (See PJM: No Change on MOPR Yet; Remand May Have Little Impact.)
“The stakes in this case are high. This generation is clearly not merchant generation, is clearly not competitive generation and represents exactly the type of subsidized generation that the MOPR was intended to address,” the complaint said.
The complaint asks FERC to rescind the exemption before the generator submits “a noncompetitive offer” into any of PJM’s Reliability Pricing Model auctions. The RTO holds annual Base Residual Auctions for capacity required three years into the future, along with incremental auctions each year leading up to the delivery year.
The Monitor declined to name the exempted generator to avoid disclosing market-sensitive information, but it described it as “a non-regulated company wholly owned by a parent company that wholly owns a regulated, vertically integrated electric utility.” The Monitor told both the generator and PJM that the generator wasn’t eligible for the exemption because it indirectly recovers costs from customers through a non-bypassable charge, according to the complaint.
Because the generator’s construction was financed entirely by the parent, the cost of capital was lower than if the generator’s operating company had sought financing on its own, the Monitor said, and that difference is the cost the generator indirectly recovered from customers through a non-bypassable charge.
However, PJM still granted the exemption.
The Monitor contended that allowing an exemption in this situation “would create a significant loophole” in the MOPR that would render it “ineffective” in similar situations because the unit is not “purely a merchant resource” as the exemption rule requires.
“Competitive market participants who invest in new generating facilities without the backing of a regulated utility or other nonmarket support” receive “essential protection” from the MOPR and would be “inappropriately disadvantaged” by the loophole, the complaint argues.
The issue was amplified by a July 7 decision from the D.C. Circuit Court of Appeals that vacated PJM’s current MOPR provisions and remanded the order back to FERC. Among the topics at issue is one of the three MOPR exemptions, which PJM and its stakeholders had jointly requested that FERC eliminate.
If FERC reverses its position and now decides to approve the request, that would make having an exemption more advantageous and the precedent of an approved loophole more problematic, the IMM said. There would be just two exemption types, and the second — known as the “self-supply exemption” — is very limited.
“This would enhance the need for an effective MOPR and correct application of categorical exemptions to the MOPR,” the complaint argues. “If the requested application of the competitive-entry exemption were approved, it would provide an easy way to avoid the defined limits on the self-supply exemption that applies to regulated utilities and to the utility in this case.”
