FOLSOM, Calif. — The CAISO Board of Governors last week greenlit new rules that allow the grid operator to constrain the operations of gas plants across the state and the Western Energy Imbalance Market (EIM), part of a package of initiatives drawn up in response to the loss of the Aliso Canyon storage facility.
The board unanimously approved the new market rules in a 5-0 vote, as the broader public discussion over Aliso Canyon intensified.
CAISO Director of Market and Infrastructure Policy Greg Cook explained to the board that there are still operational risks around the loss of Aliso Canyon. The gas constraint tool is limited to use for physical constraints on the grid, not to manage economic conditions.
“There is potential for similar types of physical gas constraints elsewhere outside of Southern California, and our operators have found that this is a valuable tool” to maintain electric and gas system reliability, Cook said.
CAISO asked the board to approve extending some temporary provisions and make others permanent as it develops a new long-term suite of market rules in its Commitment Cost and Default Energy Bid Enhancements (CCDEBE) proceeding, expected to be implemented in fall 2018.
The EIM Governing Body previously approved elements of the Aliso Canyon Gas-Electric Coordination Phase 3 proposal. (See EIM Leaders Endorse CAISO Gas Constraint Measure.) CAISO will submit the rules to FERC for approval.
The board’s approval extended a temporary rule that the day-ahead market gas price index use information published every morning to better reflect gas costs, and requires a scalar to be included for the next-day gas index to account for tight gas conditions in Southern California and higher gas costs.
Cook said he hasn’t seen much need for gas constraints in Southern California in the past year, but the ability to use the scalar would be there if unforeseen events happen.
Also approved was a right for gas generators to file for after-the-fact cost recovery of energy costs if units are mitigated down to their default energy bid.
Stakeholders generally support the gas constraint tool but do not want it to replace or affect the package of bidding rule changes being developed in the CCDEBE proceeding. Representatives from NRG Energy and Pacific Gas and Electric said there are concerns about the package but were generally supportive. But many stakeholders have commented that there are broader problems that must be adequately addressed in the CCDEBE proceeding. The Western Power Trading Forum did not support use of the gas constraint tool unless the scalar is retained.
CAISO’s Department of Market Monitoring had expressed concerns about the Phase 3 proposal, but its concerns have been addressed, including an eventual automation of the process whereby constrained transmission paths are deemed uncompetitive and constraints are implemented.
NRG Director of Regulatory Affairs Brian Theaker told the board that his company originally opposed the Aliso Canyon mitigation procedures because it distracts attention from CCDEBE and “long-standing problems with regards to the ISO bidding structure.” Suppliers cannot reflect gas procurement costs in bids and could not recover those costs, he said.
The company’s opposition has been “tempered a little bit” because of process on CCDEBE, he said. “CCDEBE is a long way off,” and the company supports extending the Aliso Canyon measures.
FOLSOM, Calif. — The CAISO Board of Governors last week approved a set of market rules designed to aid the integration of distributed energy resources and transmission-connected energy storage into the ISO’s markets.
ISO staff closely consulted with market participants over the past year to develop the Energy Storage and Distributed Energy Resources (ESDER) Phase 2 proposal in response to the growing volume of distributed resources in California. The board’s approval of the measure sends the rules to FERC for a new round of comments and review.
DER developers such as energy storage companies are aggressively moving into an area that is seen as increasingly important and profitable — balancing renewables and addressing California’s “duck curve,” which graphically describes the impact of the variable output of solar generation on the ISO grid at different times of the day. (See Report: Calif. ‘Duck Curve’ Growing Faster than Expected.)
CAISO CEO Steve Berberich told the board that ESDER Phase 2 is part of a broader strategy to accommodate emerging technologies, including demand response, storage and other new types of systems that might be coming to the grid.
“We think that leveraging them is going to be critical to how we manage the grid, and help decarbonize the grid as well,” Berberich said. He added that “we are committed to continue to work with all those that provide these services,” and with the California Public Utilities Commission.
Storage makes up 20% of the resources in CAISO’s interconnection queue, which contains 325 projects totaling 58,000 MW, according to the grid operator. Renewables represent 68% of the generation waiting to interconnect, while conventional resources account for 9%.
Beyond 10-in-10
As part of ESDER, the board approved a set of alternative energy usage baselines to assess the performance of proxy demand resources, which are DER aggregations of retail customers. It also approved new rules that distinguish between charging energy and station power for storage resources, and a net benefits test for DR resources that participate in the Energy Imbalance Market (EIM).
The ISO currently relies on a “10-in-10” baseline methodology that works well for many large commercial and industrial customers but not for all customer types, CAISO said in briefing documents. Using the 10-in-10 methodology, the ISO calculates a baseline by examining the 45 days prior to a trade date and finding 10 “like” days in which no DR was required. It then uses hourly average meter data to create a baseline representing a typical load profile, and the resource is paid for reducing usage below the baseline.
Under the new proposal, baselines for residential resources would be based on a four-day weather match that estimates what electricity use would have been in the absence of DR dispatch under similar weather and on similar days, using a control group of similar users.
Commercial baselines would be based on the 10-in-10 method with a 20% adjustment cap, an average of the previous five days and a control group. Baselines are adjusted using actual load data in the hours preceding a DR event to better reflect variables that might not appear in the historical data.
The package approved by the board also includes a new definition for station power, to distinguish between power used to charge a storage device and energy for station power. It simplifies the definition of station power to align with local regulatory authorities.
The newly approved initiative also incorporates additional gas pricing indices into the “net benefits test” that determines a price threshold to indicate when DR provides a net benefit to all purchasers by reducing the wholesale price. The price threshold is used to determine if an adjustment is required to the settlement of the load-serving entity that procured the load curtailed by the DR resource.
Greg Cook, CAISO director of infrastructure and policy, told the board that the measure allows the ISO to “take into account that the real-time market now has a much broader footprint than just the ISO balancing area, and we should take that into account in the calculation of the net benefits test.”
‘All Hands on Deck’
Tesla’s Powerpack is an example of utility-scale storage | Tesla
CAISO stakeholders are supportive of the new baselines and the station power proposals. Tesla and other storage companies urged CAISO to move quickly to develop a new DER product that would pay for storage to take excess generation, but the ISO said that measure needs more development, and it was not included in ESDER Phase 2. (See Storage Advocates Urge CAISO on DR Product.)
Ted Ko, director of policy for energy storage company Stem, told the board that the ESDER package and DER will be an important tool in reducing the duck curve and curtailments of excess renewables.
“It seems like a time for all hands on deck,” Ko said. “We should be looking for all solutions to reduce that curtailment and bring all solutions to bear.” This also includes developing the EIM and regionalization of CAISO, he said.
Stem has been participating in CAISO as a proxy demand resource and has contracts to deploy more than 400 MWh of DER over the next several years in California. The company needs the ISO to provide a market signal to know when charging is most helpful to the grid, Ko said, and technical and policy guidance from the ISO and other companies. He said that Stem and other companies want the ISO to “take this leadership position with urgency” on developing a load consumption proposal.
Berberich said that CAISO will brief the board at its next meeting on the integration of the load-consumption DER product. There are jurisdictional issues to be worked out with the PUC, he said, and he asked storage companies to contribute their ideas.
American Electric Power, once the biggest coal-burning utility in the U.S., now plans the nation’s largest wind farm, a 2,000-MW project in the western Oklahoma Panhandle that would be connected to subsidiaries in Arkansas, Louisiana, Oklahoma and Texas by a 350-mile EHV transmission line.
AEP’s total investment in the project would be $4.5 billion — $2.9 billion for the wind farm and $1.6 billion for the Wind Catcher Energy Connection line. Its Southwestern Electric Power Co. and Public Service Company of Oklahoma subsidiaries would own 70% and 30% of the project, respectively.
| AEP
The wind farm, made up of 800 2.5-MW General Electric turbines, will be built for AEP by Invenergy. In addition to being the largest in the U.S., it will be the second largest in the world, behind only the 6,000-MW Gansu wind farm in China.
PSO and SWEPCO seek approvals from regulators in the four states the project will serve, as well as from FERC, by April, AEP CEO Nick Akins said in the company’s second-quarter earnings conference call Thursday. The company will re-evaluate the project at that time.
| AEP
“We are going to have to sit down at the end of that April time period and figure out, ‘OK, what are the risks to our shareholders moving forward with this particular project, given not only the regulatory outcomes but also the other risk components that are involved with this,’” Akins said.
One of those other risk components is the project’s completion date. It has to be up and running by 2020 to qualify for the federal production tax credit, which ends at the end of 2019. Akins said AEP will recover $2.5 billion through the credit.
SPP confirmed that the project is in its generator interconnection queue for study of its impact on the system.
SPP Wind Growth
The RTO has seen considerable wind-energy development in the Oklahoma and Texas panhandles, which has caused congestion in the area. SPP will be conducting a high-priority congestion study to address the situation. (See “Committee Gives Congestion Study New Life,” SPP Strategic Planning Committee Briefs: July 13, 2017.)
AEP’s announcement came as the American Wind Energy Association reported that wind projects under construction or advanced development rose 40% year-over-year in the second quarter. Kansas became the fifth state with more than 5,000 MW of installed wind, joining Texas, Iowa, Oklahoma and California.
The transmission segment of the project is similar in scale to Clean Line Energy’s proposed Plains & Eastern Clean Line, a $2.5 billion, 700-mile HVDC transmission line that would deliver 4,000 MW of wind power from the Oklahoma Panhandle to the Tennessee Valley Authority near Memphis, Tenn.
‘Exciting Development’
“It’s a pretty exciting development for transmission,” Clean Line founder and President Mike Skelly told RTO Insider. “We’ve always believed building wind in the windiest places of the country with long-distance lines to load is a great answer for ratepayers and energy overall. These guys believe in the same thing.
“When the biggest utility says, ‘You know what? We believe that too’ … that’s a very positive thing for our industry. It bodes really well.”
Asked about advice he would give AEP given regulatory approvals and landowner opposition, Skelly said, “AEP is one of the biggest utilities we have. Far be it from me to offer them advice.”
Akins said the project would not cause AEP to shutter any of its other generators. He said only 7% of the power coming out of the wind farm “counts as capacity, so you still need the other units to provide capacity, and they fill in from an energy perspective as well.
“We’re not shutting any other units down; those units are absolutely needed. But what it does is provide more diversity from a resource perspective.”
AEP also is touting the project’s effect on its service areas’ economies, saying it will save ratepayers $7 billion over 25 years and support 8,400 jobs during construction. The project will support 80 permanent jobs once it’s operational and contribute approximately $300 million in property taxes over its life, according to the company.
AEP said it earned $375 million ($0.76/share) on revenue of $3.6 billion in the second quarter. Its earnings, adjusted for non-recurring gains, were 75 cents/share. That was short of the average estimate of seven analysts surveyed by Zacks Investment Research, which was 82 cents/share.
Eversource Energy’s second-quarter profits this year increased 13.3% over the same period a year ago, driven mainly by higher distribution revenues and lower operations and maintenance expenses.
The company reported net earnings of $230.7 million in the second quarter of 2017, compared to $203.6 million a year earlier. In a July 28 earnings call, CFO Phil Lembo highlighted the company’s transmission expansion plans, and its move away from electricity generation and into the water industry with its planned $1.7 billion acquisition of water utility Aquarion Water, which operates in Connecticut, Massachusetts and New Hampshire. Eversource expects to close the deal by year-end following regulatory approval.
ROE Revisited
Lembo commented on the D.C. Circuit Court of Appeals’ April ruling overturning a 2014 FERC order that lowered the base return on equity for New England transmission owners from 11.14% to 10.57%. The court said the commission failed to meet its burden of proof in declaring the previous 11.14% rate unjust and unreasonable. (See Court Rejects FERC ROE Order for New England.)
In June, the New England TOs — including Eversource — filed with FERC to begin billing customers based on the prior ROE, with retroactive billing to June 8 of this year, 60 days after FERC assembles a quorum.
The commission has lacked the necessary three-member quorum since the February departure of former Chair Norman Bay and has been down to one commissioner — acting Chair Cheryl LaFleur — since Colette Honorable left last month. LaFleur may be joined by four new members if Democrat Richard Glick and Republicans Kevin McIntyre, Robert Powelson and Neil Chatterjee win Senate confirmation. (See Trump Names Energy Lawyer McIntyre as FERC Chair.)
“As a reminder, every 10 basis points [0.1%] of change in transmission ROEs results in about $3 million after-tax earnings annually,” Lembo said. The posted Q2 earnings reflect the lower ROE rate ordered by FERC.
Northern Pass
| Eversource
Company executives also touted the benefits of a proposed project designed to help Massachusetts meet its ambitious clean energy goals.
Eversource and Hydro-Québec on July 27 jointly bid the Northern Pass transmission line into the state’s solicitation. The 192-mile line would carry 1,090 MW of Canadian hydropower into New England and deliver up to 9.4 TWh/year for a period of 20 years starting in December 2020. The RFP encouraged bids able to begin delivering all or part of the state’s required 9.45 TWh/year of renewable energy by the end of 2020. (See Hydro-Québec Dominates Mass. Clean Energy Bids.)
New Hampshire’s site evaluation on Northern Pass is moving forward this summer, and the company estimates the project will be fully permitted by the end of September, allowing construction to start in early 2018, Executive Vice President Lee Olivier said.
“We believe this schedule would put us ahead of any other major project to import Canadian hydro into New England,” Olivier said. “Our confidence in the construction schedule is also supported by the firm contracts we have with two of the most pre-eminent firms in the world in terms of electric transmission design and construction, ABB and Quanta Services.”
Bay State Wind, a 50/50 partnership between Eversource and DONG Energy, will also bid into a separate wind project RFP in December to develop an offshore site south of Martha’s Vineyard.
Regulatory Activity
The company also noted that Massachusetts regulators last month wrapped up hearings on rate cases filed by Eversource subsidiaries NSTAR Electric and Western Mass Electric, which have asked to raise their base distribution rates by $60 million and $36 million, respectively. Eversource also sought approval to combine the two utilities.
“Hearings have concluded on the rate case, except for rate design topics,” Lembo said. “We expect a decision on the financial aspects of the case by the end of November, with the rate design decision around year-end. New rates would be effective in January of 2018 and to date we’ve had no surprises in the rate review process.”
In New Hampshire, binding bids to buy the company’s Public Service of New Hampshire generation fleet are due in August. “There, too, the overall divestiture process is moving along well and we expect regulatory approval of the sale by the end of the year, with securitization activities to follow soon after the closing,” Lembo said.
Tony Clark’s term as FERC commissioner ended nine months ago, but he hasn’t stopped thinking about the issues that animated him during his four-year tenure.
Clark, a non-attorney who joined law firm Wilkinson Barker Knauer as senior adviser in January, had his coming out in a 16-page white paper titled “Regulation and Markets: Ideas for Solving the Identity Crisis.” It was released at the National Association of Regulatory Utility Commissioners’ summer meeting in San Diego, a fitting venue for Clark, a former North Dakota regulator who served as NARUC president before his FERC appointment.
Clark’s paper mostly addresses the eastern organized markets being buffeted by state policy initiatives, but he also discusses new technologies and trends. He offers his familiar wit, for example, linking the 1978 Public Utility Regulatory Policies Act (PURPA), which Clark has long criticized, to the era of bell bottoms and disco.
Nothing in his recommendations are particularly divisive, surprising or novel. His recommendations on performance-based ratemaking and changes to distribution rate structures, for example, are sensible but no surprise to anyone following New York’s Reforming the Energy Vision (REV).
Perhaps his most interesting observation is that moves by New York, Illinois and New England states to subsidize nuclear plants or require utilities to sign out-of-market contracts for renewables have exposed “how thin the veneer of pro-market fidelity” is. It’s an issue he first considered in the 1990s when he — then a state legislator — weighed whether North Dakota should abandon its traditional regulated utility model for retail choice.
Although his “philosophical conservative” side favored competitive choice, his “operational and practical conservative” side won out. “Like nearly all other states with much below-average-cost electricity, the value proposition for [competition in] North Dakota did not pencil out,” he decided.
Clark concludes that recent moves to increase state control over wholesale generation market “is consistent with the factors that have driven public policies in electricity for the last two decades, not a departure from it.”
“For many, a ‘freer market’ was never the end goal,” he said. “The market was a tool. Affordable power was the goal. The current markets are still procuring affordable power, but many state public policy makers no longer see that as the only goal.”
He also expressed doubts that the eastern RTOs will succeed in their efforts to accommodate state choices while maintaining capacity markets as the primary source of resource adequacy. “While I applaud their efforts to look at creative solutions, I am skeptical of whether further dissection of administrative auctions into state-sponsored resources and competitive resources can succeed,” he said. “The complexity of these administrative constructs is remarkable as it exists today. Layering even more auctions, set-asides and carve-outs onto to the current construct may ultimately tumble the house of cards.”
RTO Insider talked to Clark last week about his paper and his new role. This interview has been edited for length and clarity.
RTO Insider: OK, so I read through your white paper and I’m curious: Who was the audience for the white paper and what was your goal in writing it?
Clark: Yeah. Well, I suppose there’s two audiences. One is more general and then one is probably a little bit more specific. The general audience is just for the public policymakers and certain thought leaders within the electric industry. On a more specific level, the way the paper turned out, it tended to be pretty focused on states. What I would hope is, especially thought leaders in the states in regulatory commissions — but also in legislatures and governors’ offices — would take a look at it and say, “You know what? There’s some things we should be thinking about.” So that at least we’re purposeful as we’re moving through this time of transition in the electricity sphere. The concern is that it’s not purposeful and it’s sort of an ad hoc collection of moves like I talked about in the paper, which is one piece at a time, where we keep layering on all these different public policies that when you step back and look at, it may not make sense in the whole.
RTO Insider: Yes. I liked your reference to the Johnny Cash song [“One Piece at a Time,” which tells a story of an assembly line worker who sneaks Cadillac parts out of the factory, later building a car mismatched from models from 1949 through 1973.] That’s one of my favorite songs.
Clark: Yeah, that’s a great song.
RTO Insider: Now that you’re no longer a commissioner, were there things in this paper that you said that you would not have been able to say before?
Clark: That’s an interesting question and I hadn’t thought of it that way. I don’t think so. I mean, it’s not dissimilar to some things that I thought and said along the way at first. It’s probably the sort of biggest compendium of all these thoughts put together in one spot. I probably would have said similar things. It’s just when you’re in the commission, you usually don’t have the time, sometimes, to sit down and really think about these things a little bit more holistically. Your day-to-day grind of just moving through your cases kind of takes things over. … Now I have a little bit more time to, I guess, sit back and contemplate.
RTO Insider: I recall covering [Wilkinson Barker Knauer partner] Raymond Gifford at the [Independent Power Producers of New York] conference in New York back in May. The subject there was the carbon adder, and he had said, “It’ll never happen.” (See Carbon Adder to Test FERC’s Independence, IPPNY Panelists Say.) He agreed that “the most elegant solution is you price carbon into the market” but said “FERC is not going to sign off on a carbon imposition.” Do you agree with that?
Clark: Well, generally yes. I mean, some of it depends a little bit on how you frame the question. If the question is, “If the states, or a collection of states, or the federal government for that matter” — [chuckles] but I don’t see that going to happen any time soon — “put on some sort of carbon adder, would FERC recognize it and allow it to be bid into the markets?” I think the answer there is probably “yes.” The commission already does that in the case of [the Regional Greenhouse Gas Initiative] and California. Other governmental bodies through their own legitimate authority putting on a carbon adder — would the commission allow that to be bid in the market? I think so, because it would just be like any other governmentally imposed cost: It’s allowed to be offered into the market.
Now, do I think FERC on its own motion is going to go out and throw on a carbon adder? I don’t think so. I don’t think it would be a wise idea beyond that. I mean, one — just take the politics of what the commission is [facing] now and for the foreseeable future. I don’t think it’s going to happen. No. 2 … it wouldn’t be in the commission’s own interest to do it for a number of reasons. You’d get beat up on Capitol Hill like you can’t imagine. And it probably is a little bit, I think, legally suspect. … I think it’s a stretch under the Federal Power Act. … And then No. 3, which is as big as anything — if you’re a commissioner who is interested in seeing the potential benefits of a joint dispatch model [traditionally regulated states that have joined ISOs or RTOs, such as most of MISO] migrate to other areas of the country, the fastest way to stop that development would be for FERC to go in and start imposing carbon taxes.
And if you look at what’s starting to come together in the West, we’ve talked about not just the [Energy Imbalance Market] but potentially more of a joint dispatch market in certain regions. … If you want western commissioners to flee from that idea and never come back to FERC again, [never] talk about it, just throw on a carbon tax. I think it would be self-defeating itself in terms of development of markets. It would probably halt markets where they are, in their tracks. You might even have some states start seriously thinking about pulling out of markets that they’re already in. If you’re from the part of the country I’m from — big red states in the middle of the country that are part of an organized market — if FERC starts looking at levying quote-unquote “carbon taxes” on its own, theoretically, you could see a real backlash in state legislatures in terms of what they allow their utilities to do. And remember that … these markets, they’re voluntary.
RTO Insider: When I was reading through your recommendations, they all seemed very sensible, very much in accord with some of the things that have been discussed in other states. For example, [New York’s Reforming the Energy Vision initiative], with their attempt to de-couple usage from revenues and provide ways for performance-based ratemaking and ways for utilities to make money as system platforms. Am I missing anything in your paper? Was there anything that you felt where you were striking new ground, where you were carving out new proposals, or were you more surveying the landscape and saying, “This is a round-up of what I think makes the most sense,” based on the current state of play?
Clark: Yeah. I think it’s probably more the latter, and my hope was to put it in the conversational style, so that it was accessible to a wide variety of policymakers. Some of them maybe don’t every day play in the electricity space. As much as anything, it was probably a distillation of trends that are out there and potential ways to frame the issues as you think about it.
A lot of that deals with rate design, making sure that you’re getting the distribution side of things right because this grid is changing. If you keep the same old rate structures that you’ve always had, you’re going out come out with a lot of arbitrage opportunities for new entrants and things like that. You want utilities to be able to provide the platform that allows for other players to do what they’re going to do, but to do it on a level playing field in a fair manner that allows them to, and gives them incentives to, invest in that network.
RTO Insider: You’re not going to have a robust distribution side network if you don’t come up with a mechanism to allow those investments to be made. Anything I haven’t touched on that you think is important in the context of this paper?
Clark: The thing that struck me as interesting over the last few years is, I thought, if there’s one region of the country where you might actually get a strong consensus for some sort of carbon price, it was going to be New England because you’ve got, politically, a group of states that probably are seeing the issues [similarly] and they’ve already joined RGGI and are part of the organized market.
I would have thought there might be a coalition here that says “maybe you need to step back from some of the other public policies and instead really depend on carbon price to drive the market.” But it’s just never coalesced and I think it shows the difficulty — even where there’s relatively fertile ground for policymakers to rally around the very transparent carbon price. Because it really — it’s transparent, which is maybe why it’s so tough to get done even under favorable circumstances.
RTO Insider: Yeah, I think some of the smaller [New England] states are just not as willing to take on more renewables in the way that Connecticut and Massachusetts are. We heard that loud and clear in some of the sessions we’ve attended from the likes of New Hampshire and Vermont and Maine, that the size of the carbon price, to make a difference, would be kind of a non-starter for them.
Clark: Yeah. That’s just it. RGGI, as I mention in the paper, has never really been used to strike dispatch or drive resource selection. It’s really been just a funding source for energy efficiency programs and things like that. It funds programs at the state level, but it doesn’t really drive resource selection in any meaningful way if the prices are just set too low.
RTO Insider: Right, right. Well, great. Well, thank you very much for your time this morning. I appreciate it.
Speaking in apocalyptic terms, FirstEnergy CEO Chuck Jones said Friday that he thinks the “country is heading for a disaster” because of its over-reliance on natural gas for generating power.
In response to a question during FirstEnergy’s second-quarter earnings conference call, Jones said one type of disaster “could be a national security type of issue. We are taking the most sophisticated bulk electric system that exists anywhere in this world and putting it on top of a bulk gas system that is very unsophisticated, and that sets up security risks if there were ever an attack on that bulk gas system.”
Jones | First Energy
The other type of disaster, he said, could be economic. “We are getting to where we are relying too much on one fuel source for the generation of electricity, and I think fuel diversity is critical to keeping economic stability. With where gas is priced now, if anything happens to cause that gas price to go up again and create a volatility in the gas markets, the volatility in electric markets is going to be so great that I don’t think industry in our country is going to be able to tolerate it.”
There’s no doubt that cheap gas has been disastrous competition for FirstEnergy’s aging merchant generation fleet. The company lost $1.1 billion in the second quarter of last year, largely because of the closure of five uneconomic coal plants. The company earned $174 million ($0.39/share) on revenue of $3.3 billion in 2017’s second quarter.
FirstEnergy plans to exit the competitive generation business and focus on its regulated utility operations by selling its generation units or getting them classified as regulated assets on which it is guaranteed a rate of return. The company’s FirstEnergy Solutions (FES) subsidiary owns 15 power plants, including three that use nuclear fuel and four that are coal-fired, and low natural-gas and falling renewable energy prices have battered it so badly that Jones has considered having it file for bankruptcy protection. (See FirstEnergy Wants out of Competitive Generation.)
In last week’s earnings conference call, Jones said FES will be talking with a group that says it represents more than 80% of the unit’s creditors and that he will be taking part in the conversation. Jones said the group called FES and “outlined a formula for a potential discussion that was interesting enough that FES decided it was worth pursuing.”
“I think we always knew this was going to happen at some point in time,” Jones said. “I think it is clearly the preferred route if we end up in a bankruptcy proceeding with FES to do it through a structured settlement that all parties are comfortable with.”
FES has done some settling already. In April, the company agreed to pay $109 million to settle a legal dispute with two railroads concerning coal transportation contracts that the company said it should have been allowed to exit because it was forced by new environmental regulations to close some of the plants to which the railroads delivered. Jones said FirstEnergy is talking to one of those railroads and another one concerning a different dispute and remains “optimistic that a settlement can be reached.”
FirstEnergy has tried to persuade Ohio legislators and regulators to treat its power plants as rate-base units but hasn’t been successful. It also tried to get Ohio regulators to give it a subsidy of $4.46 billion over eight years, but they only gave it $612 million over three years. (See PUCO Rejects FirstEnergy’s $558M Rider, OKs $132.5M.)
Even though it’s getting out of competitive generation, Jones said FirstEnergy will continue to press for subsidies to allow nuclear plants in competitive generation markets to continue operating. Ohio was considering legislation that would set up a zero-emission nuclear (ZEN) resource program similar to the zero-emission credit (ZEC) programs established to funnel money to nuclear plants in New York and Illinois.
“I am going to continue to fight for this ZEN legislation because it is the right thing to do for the state of Ohio; it’s the right thing to do for those assets,” Jones said. “It gives those assets the best chance of running under new owners.”
Jones also said FirstEnergy is looking forward to the release of the Department of Energy study of electrical markets and reliability, which, he said, “is expected to address economic and security risks associated with the premature closure of the nation’s fuel-secure baseload generation as a result of regulations, subsidies and tax policies.”
“We’re optimistic that the final DOE study … could offer solutions to address this national concern. And the FES board is closely following this effort, which is expected to help them determine the right path forward for FES.”
Calpine CEO Thad Hill confirmed Friday that the Houston-based merchant generation company is looking to be acquired. Citing anonymous sources, Bloomberg reported on Wednesday that Energy Capital Partners is in advanced talks to purchase Calpine and could announce a deal as soon as this week.
During a call to discuss second-quarter results, Hill said that “the public equity markets have undervalued our business and underappreciated our strong track record of executing on our financial commitments and our stable cash flows.”
The company’s board of directors decided to explore “strategic alternatives” in early spring, Hill said. Executives do not plan to provide updates on sale discussions unless required by law and do not know if they will result in any sale.
Calpine’s adjusted second-quarter profit was $419 million, compared with $452 million during the same period last year, an 8% drop. Profit for the first half of the year was $745 million, compared with $826 million in 2016.
The company saw higher peak-time prices for its Texas plants in the constrained Houston zone, and PJM’s most recent capacity auction yielded good results for the company’s plants there.
Hermiston Power Plant | Calpine
“The larger storyline in the east is the integrity of their market structures given the potential for nuclear bailouts in some states and the pursuit of renewables in others,” Hill said.
Calpine lists as current assets its 80 power plants in operation or under construction in 18 states, totaling about 26 GW of capacity. Company executives elected not to take questions from analysts regarding the second-quarter results.
PG&E Files $74M Transmission Charge
Pacific Gas and Electric parent company PG&E Corp. reported that its profits rose by 97% to $406 million on a non-adjusted basis compared with the same period a year ago. The increases resulted from resolution of its 2017 electric and transmission and storage rate cases, the company said.
During a July 27 earnings call, CEO Geisha Williams said the company had filed with FERC for a $74 million transmission revenue increase beginning next year for reliability work and modernizing substations.
“It is through these types of investments and these continued investments in our grid that we can help ensure our system is stable and that we can continue providing the high-quality service that our customers have come to expect,” Williams said.
The company’s 2,240-MW Diablo Canyon nuclear plant was in planned refueling when a scorching heat wave hit California, and nearly 2% of customers lost power on a peak day. At times during the heat wave, renewable portfolio standard-qualified resources made up more than half of energy supply, Williams said.
PG&E received 98% of its rate base request in its general rate case, representing an 1% increase in authorized revenue for 2017. It expects a decision later this year on a settlement filed with the California Public Utilities Commission on its proposal to retire Diablo Canyon. The company in January reached a settlement with environmental groups and others over the retirement of the plant, due to shut down in 2025.
SCE Profits Down
Southern California Edison’s (SCE) profit fell by $11 million to $307 million in the second quarter “due to a reduction in [PUC] revenue related to prior overcollections,” the company said. Year-to-date revenue was $656 million, compared with $612 million in the first six months of 2016, with some influence from rate case and operations and maintenance numbers.
Edison International CEO Pedro Pizarro said July 27 that the company has hired an adviser to study selling its SoCore Energy solar business. “We just wanted to explore whether there are other options, including the potential for a sale,” he explained.
SCE’s capital expenditures are trending downward from the originally forecast $4.2 billion and are currently expected to be about $3.8 billion because of delays in transmission spending, lower customer growth and lack of approval of grid modernization.
SCE is in the midst of a rate case, and in June it lowered its capital funding request by about $420 million, $300 million of which is devoted to grid modernization. The company has run into opposition to its grid modernization plan from environmental groups, which want more focus on distributed energy resources and renewables.
Xcel Beats Expectations
Xcel Energy on Thursday reported second-quarter earnings of $227 million ($0.45/share), up from $197 million ($0.39/shar) a year ago. That beat analyst expectations gathered by Thomson Reuters of 42 cents/share.
Xcel’s revenue came in at $2.65 billion, ahead of $2.6 billion expectations.
The Minneapolis-based company said rate increases in Minnesota, New Mexico, Texas and Wisconsin led to higher margins. Xcel also benefited from higher natural gas profit margins, lower operations and maintenance expenses, and a lower tax rate.
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.
