With unprofitable power plants dragging down its bottom line, FirstEnergy says it is calling it quits on competitive generation. And its days as a competitive retail supplier may be numbered as well.
CEO Charles Jones said during the company’s third-quarter earnings call Friday that the company will seek to sell its 17,000 MW of competitive generation or persuade Ohio regulators to transfer them into rate-base units.
“After the election is over … we plan to begin legislative and regulatory efforts designed to preserve our remaining generation assets. We are looking to convert competitive generation to a regulated or regulated-light construct in Ohio,” Jones said. “We’re also open to exploring the sale of any or all of these assets, particularly the gas and hydro units at Allegheny Energy Supply. If we find that one or more of these options are not viable, we’ll also consider deactivating additional competitive generating units, similar to the ones we announced this summer at Sammis Units 1 through 4 and Bay Shore.”
Sammis Power Plant | Bechtel
He also raised the prospect of a bankruptcy filing for FirstEnergy Solutions, the company’s competitive retail arm.
The news came as FirstEnergy reported earnings of $380 million ($0.89/share), down slightly from earnings of $395 million ($0.94/share) for the same period last year. The company expects a loss of $1.30 to $0.90/share for the year.
Jones said the company would be seeking a “solution” for its nuclear units in Ohio and Pennsylvania “that recognizes the environmental benefits of these established baseload-generating resources.” New York regulators’ approval of a zero-emissions credits system to preserve the state’s upstate nuclear plants has been challenged in court. (See Federal Suit Challenges NY Nuclear Subsidies.)
$1.1B Loss
Jones’ announcement on the fate of FirstEnergy’s merchant generation was his most definitive yet. After posting a $1.1 billion second-quarter loss tied to the closure of five coal-fired plants, Jones said the company would not make any large investments to prop up the credit rating of its generation business. (See FirstEnergy Posts $1.1B Loss, Eyes Exit from Merchant Generation.)
Last month, the company was disappointed when Ohio regulators rebuffed its request for a $4.46 billion subsidy spread over eight years, approving instead $612 million over three years. (See PUCO Rejects FirstEnergy’s $558M Rider, OKs $132.5M.)
Jones last week blamed “weak” current prices and “anemic” demand forecasts for the poor financial performance of the generation fleet, which he said “is weighing down the rest of our company.”
“And while we have fought hard, we cannot continue to wait for an upturn,” he said. “We believe an accelerated timeframe is necessary so that we can remove lingering uncertainty, especially for our employees, and ensure that our company is singularly focused on the transition to becoming a fully regulated company.”
Jones estimated it would take 12 to 18 months for the company to execute its plans for its generation.
He also warned of deteriorating conditions at FirstEnergy Solutions, which sells retail energy to residential, commercial and industrial customers in the Northeast, Midwest and Mid-Atlantic regions.
“Further downgrades … by the rating agencies could require posting additional collateral of $355 million,” he said. “The continued viability of FirstEnergy Solutions is also pressured by some additional risks over the near term. These risks, which include an inability to implement our strategic alternatives in a timely manner, an adverse outcome related to a coal transportation contract dispute at FirstEnergy Solutions, or the inability for FirstEnergy Solutions to extend or refinance debt maturities of $515 million in 2018 could cause FirstEnergy Solutions to take additional actions, including restructuring its debt and other financial obligations or seeking bankruptcy protection.”
In West Virginia, meanwhile, FirstEnergy’s Mon Power subsidiary plans to issue a solicitation by the end of this year to address its generation shortfall.
VALLEY FORGE, Pa. — After months of debate, PJM’s Manual 15 revisions on fuel-cost policies and hourly offers won the approval of the Market Implementation Committee on Wednesday.
The changes are based on FERC’s approval of related Tariff changes that were filed in August (ER16-372).
Catherine Tyler Mooney of Monitoring Analytics, PJM’s Independent Market Monitor, questioned why some language on the review process that the Monitor and PJM had previously agreed upon had been struck from the revisions.
PJM’s Jeff Schmidt explained that elsewhere in the manual, the policy review was detailed as a “collaborative process” between the Monitor and PJM, so it needed to read that way everywhere in the manual. “The way we had it broken up before, it was staged,” he said. “It didn’t make sense for one [section] to be staged or stepped, and one to be at the same time.”
The section in question put generators on a five-day clock for responding to inquiries from the Monitor. “If the [Monitor] lets us know you want us to keep track of the clock, we’ll start the clock,” Schmidt explained. “If you have some specific question during the process about the fuel-cost policy, you have to let us know [to start the clock]. Then we’ll keep track of it.”
Mooney indicated that the explanation wasn’t satisfactory, but she declined to continue the debate. The exchange was the latest skirmish in an ongoing dispute between PJM and the Monitor. (See PJM Attempting to Usurp Market Mitigation Role, Monitor Says.)
Several stakeholders, including Mike Borgatti of Gabel Associates, had concerns with how that plan would be implemented to ensure a generator is aware whether it’s on the clock or not. Schmidt assured him that PJM would make them aware.
Schmidt’s efforts were good enough for Calpine’s David “Scarp” Scarpignato. “I’d like to do something I usually don’t do: I’d like to commend you,” he told Schmidt. “It’s pretty specific what this engineering judgment is referring to, and I think this is a well-written sentence.”
The revisions were endorsed with seven objections and two abstentions.
‘Fully Metered’ EDC Definition OK’d
Members endorsed by acclamation Manual 28 changes describing a “fully metered” electric distribution company.
The changes were developed in response to a stakeholder request for a definition of the phrase, which was added in a recent update to Manual 01: Control Center and Data Exchange Requirements.
The new language in Manual 28: Operating Agreement Accounting defines a fully metered EDC as one that “reports hourly net energy flows from all metered tie lines to PJM via Power Meter and revenue meter data for the hourly net energy delivered by all generators within that EDC’s territory via Power Meter, for the purposes of energy market accounting.”
PJM’s Tom Hauske had come to the MIC meeting hoping for endorsement of changes to the Tariff and Manuals 11, 12 and 28 relating to operating parameters. But the Monitor’s concerns about definitions and modeling shelved that idea and the item was changed from an endorsement to a first read. (See “Stakeholders Approve Last-Minute PJM-IMM Operating Parameters Collaboration,” PJM Market Implementation Committee Briefs.)
Monitoring Analytics’ Joel Romero Luna raised concerns with how the definitions were applied, specifically pointing to what he saw as an over-complication of how to handle facilities with multiple breakers. He suggested standardizing the language to “the last breaker” throughout the revisions.
“When there’s one breaker, that’s always the last one,” he said.
Based on Luna’s concerns, Dave Pratzon of GT Power Group suggested delaying the vote until the Monitor had revised the language. “Personally, I can’t see voting on something where the [Monitor] is going to come back and make changes,” he said.
More Adjustments for Five-Minute Settlement
PJM will transition from an hourly calculation to a five-minute calculation for balancing spot market energy charges in order to eliminate an imbalance created when values such as demand, generation, imports and exports are calculated on different time scales, PJM’s Ray Fernandez explained.
Additionally, PJM proposed including the value of the generation and load imbalance in the transmission loss charges calculation and the transmission loss credits allocation. (See “Order 825 Progress,” PJM Market Implementation Committee Briefs.)
“The key piece to remember in here is the five-minute [generation-to-load] imbalance component,” Fernandez said. “That component is part of the balancing spot-market charge.”
PJM’s shortage pricing proposals from Oct. 26 and Nov. 2. | PJM
Next, PJM’s Rebecca Stadelmeyer explained the RTO’s proposed adjustments to shortage pricing to integrate with five-minute settlement requirements. PJM’s plan would change the scarcity signal for the maximum $850 penalty factor from the economic maximum of the single largest contingency to the highest actual output of a single unit. Next, it would add two lower “steps” that would trip a $300 pricing level. One step would be calculated as the highest actual output plus 190 MW — a static number derived from the synchronous reserve mean of the Mid-Atlantic Dominion zone plus one standard deviation. The second step would be calculated as the previous step plus an extension.
Stakeholders had several concerns with the proposal. Direct Energy’s Jeff Whitehead questioned the value of additional penalty thresholds that would just trigger lower levels of scarcity pricing more often. “I’m still a little perplexed as to why the reserve requirement is even being discussed here,” he said.
PJM argued it would reduce volatility.
IMM Clarifies Fuel-Cost Policies
Bowring outlined fuel-cost issues he’s observed and how they should be handled. First, he addressed penalty gas — gas used by generators that exceeds the amount the generator committed to using that day.
“The basic issue with penalty gas is it’s intended to be an incentive to not use the gas,” he said. “It’s not appropriate to include that in the cost of your gas.”
Stakeholders took exception to that, saying not being able to recover those costs would make them less likely to respond if called by PJM.
Bowring also discussed how generators should account for the costs of “ratable take” gas — gas that is not guaranteed to be available. “If a generator chooses to take a less-firm service, that’s fine, but they should take the risk,” he said.
Again, stakeholders were less than enthusiastic with Bowring’s perspective. “We need to be able to recover the costs of responding to PJM’s request. If we can’t do that, we’re going to have issues,” Dynegy’s Jason Cox said. (See Heeding Stakeholders, PJM Reduces Proposed Fuel-Cost Penalties.)
Generators Displeased with FTR Adjustments
To comply with FERC’s order on assigning balancing congestion costs, PJM is proposing several changes to its financial transmission rights market. First, it plans to assign all real-time balancing congestion to load. Along with that, PJM proposed returning to auction revenue rights holders any FTR auction and day-ahead congestion surplus after ARRs and FTRs are fully funded.
“PJM believes the allocation of FTR surplus should change to align closer with allocation of balancing congestion,” PJM’s Asanga Perera said in his presentation.
PJM also proposed annual replacement of retired Stage 1 paths. “We would only consider any future replacements as units retire. in other words, we wouldn’t be doing this process over and over every year,” Perera said. PJM has proposed a hybrid plan that would replace merchant paths RTO-wide and zonal-wide rate-based paths only in that zone.
Calpine’s Scarp was concerned with this approach. “I think you need to go back to the original presumption, which is, ‘Those who pay for the transmission get the rights,’” he said. “To say I have [capacity injection rights] and don’t get some of the incremental ARRs doesn’t make sense.”
“Why would a generator need a congestion hedge?” asked PJM’s Tim Horger. “They have no load.”
“I think the generator deliverability analysis lines up directly with the load deliverability analysis,” Scarp said. “There’s a parallel here. You can ignore it if you want, but I’m telling you it exists.”
The Long Island Power Authority is inching toward New York’s first offshore wind farm, which would supply 90 MW of electricity on a site off the eastern tip, said Mike Voltz, director of energy efficiency and renewables for PSEG-Long Island, which operates the power grid for LIPA. “We expect that power purchase agreement to go to the LIPA board of trustees in December for approval.”
David Mooney, director of the Strategic Energy Analysis Center at the National Renewable Energy Laboratory, discussed how New York could meet its 50% clean energy mandate. Because the current hydropower penetration of 20% is not expected to increase substantially, wind and solar would make up the remainder.
“There’s enough flexibility that exists in the system to be able to manage 30% penetration of wind and solar, and that’s without adding storage to manage variability,” he said.
Charles Fox, senior director of regulatory affairs and business development for fuel cell manufacturer Bloom Energy, praised New York’s level of sophistication in discussing clean energy policy. But he said the state needs to proceed with caution.
“The process of implementation is absolutely critical. We all want to get to the promise of Reforming the Energy Vision, but it’s important to do that to recognize that not only customers but financial institutions have entrenched business models that are going to need to change to finance projects. With companies that may have power purchase agreements in seven to 10 states, and when you suddenly change the rules in one of those places, it has a reverberating effect through just the law of unintended consequences.”
Richard Kauffman, Gov. Andrew Cuomo’s chairman of energy and finance for New York, took on critics of the zero-emission credit program, which would subsidize upstate nuclear plants to keep their carbon-free generation available for another 14 years.
“It would be great, as some critics would have us do, to say ‘let’s replace the nuclear plants with renewable energy. Let’s do that right now.’ It’s just not practical,” he said. “We cannot snap our fingers and have it done. We need to recognize the role nuclear will play in a transition to a renewable energy future, as no one has put forth a credible plan for cost- and time-effective replacement.”
Jim Muscato, a partner at the Young/Sommer law firm, which has represented wind developers for 15 years, said permitting has become more difficult as state agencies like the departments of Health and Transportation become involved.
“The totality of the siting process is that it will take about three years. One of the specific challenges is that the government does not speak with one voice. When getting through the preapplication process, we’ve had more government agencies get involved in the process than have ever been involved before. We’ve had 15 years successfully siting projects, but now we are working with agencies that had never been involved before.”
INDIANAPOLIS — After demonstrating the capabilities of its new 20-MW battery for five months, Indianapolis Power and Light says it’s time for it to get paid.
The energy storage system at its Harding Street Station here has been providing MISO with primary frequency response since May. But the company told FERC in an Oct. 21 complaint that the battery is “supporting the grid with no means for compensation for the services rendered” (EL17-8).
Interior of IP&L’s Harding Street facility | AES
The complaint asks FERC to compel MISO to update its energy storage definitions and compensation.
“Nothing [in the Tariff] exists to allow the battery to participate in the regulation market and be appropriately paid,” Lin Franks, IPL’s senior strategist for RTO, FERC and compliance initiatives, told RTO Insider in an interview. “We’re hoping FERC will see the wisdom in compensating automatic frequency control, injecting when frequency is too low and withdrawing when frequency is too high.”
IPL argues its battery should be paid instead of charged when “withdrawing [power] in response to a frequency deviation.”
Franks said IPL is not trying to be critical of MISO in making the filing. She pointed out that in 2009, when MISO opened its ancillary services market in accordance with FERC Order 888, the requirement did not include details on how fast-start resources recover costs.
“That was fine for back then, but now that we have a lithium ion battery in the MISO footprint, it’s no longer just and reasonable. What was just and reasonable in 2009 isn’t necessarily just and reasonable now,” she said.
Franks said creating proper definitions and a compensation mechanism is an “industry-wide kind of challenge.”
“Nobody is mad at anybody. It’s just time to make a change … and we don’t want this to get on the back burner,” Franks said.
The battery — consisting of eight 2.5-MW blocks — is using the interconnection facilities of two gas turbine generator units, which connect to the Harding Street South substation. (See FERC Approves 1st Storage GIA in MISO.)
Franks said settlement and dispatch for IPL’s lithium ion batteries are “vastly different” than for MISO’s current Type II storage energy and demand response resources. IPL claims MISO’s dispatch protocols are currently tailored to flywheel storage only.
MISO spokesperson Jay Hermacinski said the RTO is assessing its next steps before responding to the complaint.
“It is relevant to point out that at MISO and across the industry, there are numerous discussions at both the policy and technical levels to determine the most efficient and effective ways to integrate new technology, including storage, to the grid,” Hermacinski said.
He added that MISO has begun work on broader storage issues, starting with a stakeholder workshop in January and through its market roadmap process. He also said MISO staff will attend FERC’s technical conference on storage Wednesday (AD16-25). (See “FERC Calls Tech Conference on Storage,” Federal Briefs.)
MISO is currently considering including medium-term energy storage resources in its definition of DR resources. (See MISO Stakeholders Provide Ideas on Incorporating Storage.) IPL called the current stakeholder process “indeterminate” and asked for “tight time limits on any required MISO compliance filings.”
Franks insists that MISO should gather stakeholders to work on new storage definitions. “You really have to start all over. It’s a very time-consuming process,” she said.
IPL has committed to sharing “as much data as it practically can,” Franks said, to help explain the battery’s benefits.
In its filing, IPL suggested using PJM’s Regulation D payment factor as a provisional model until MISO can develop its own method for compensation.
IP&L’s Harding Street Facility exterior | DOE
PJM developed the regulation market payment after being approached by IPL parent company AES in 2009. AES’ Laurel Mountain facility in West Virginia — 98 MW of wind generation and 64 MW of integrated battery-based storage — has been providing PJM regulation service since October 2011.
The PJM payment mechanism is “certainly not going to be perfect for the MISO footprint,” Franks said. “But for the interim period, we’re suggesting that it is equitable and fair until MISO does its own body of work.”
Franks said working through the stakeholder process to incorporate a new storage definition and compensation into the Tariff would take about two to five years. She added that while IPL has a few ideas on what storage definitions might look like, it would rather reveal them in MISO’s stakeholder process.
“We prefer to share our data and testing and experience and work together to find a way that actually works to present to the stakeholders. No man is an island,” Franks said.
The Energy Storage Association lauded IPL’s move and urged FERC to take action to stop IPL from having to “operate the system in a suboptimal manner” and degrade the useful life of the battery.
“Without proper market structures that recognize the value delivered by energy storage systems, there is no way that the system can be dispatched cost-effectively. And without market signals that reflect the storage system’s operating parameters, the storage system could be unintentionally compromised or damaged,” the group said.
IPL’s complaint has attracted motions to intervene from American Municipal Power, Calpine, the Electric Power Supply Association, the Indiana Utility Regulatory Commission, Alliant Energy and the Coalition of MISO Transmission Customers and battery maker Alevo.
ALBANY, N.Y. — A coalition of environmental groups and clean energy developers on Thursday called for upgrades in New York’s transmission system at the Alliance for Clean Energy New York’s 10th Annual Conference.
“Today’s unique circumstances dictate that the rapid construction of new high-voltage transmission infrastructure should be an important component of the state’s strategy to meet its clean energy goals,” said ACE NY, the Sierra Club, Pace Energy and Climate Center, Environmental Advocates of New York and the Natural Resources Defense Council in a statement released at the conference.
“When we’re looking at transmission projects for the future, we need to see them through the 50% renewables lens,” ACE NY Executive Director Anne Reynolds said, referring to Gov. Andrew Cuomo’s State Energy Plan, which requires the state to procure 50% of its electricity from renewables by 2030.
The joint statement was also filed with the New York Public Service Commission, which is overseeing two transmission initiatives under the public policy provisions of FERC Order 1000. (See NYISO Identifies 10 Public Policy Tx Projects.)
The groups had a willing ally in NYISO CEO Brad Jones, who addressed the attendees at the morning session. He decried the 10- to 12-year process to get transmission built, advocating an expedited process of no more than six years.
“We need to develop our transmission system with an eye toward where renewables will be built,” Jones said. He said transmission developers need to build what he called a collector system, where renewables can be easily connected.
He said the ISO wants to lessen risks for energy developers who currently may seek less-than-optimal sites to access existing transmission; Jones had experience in Texas helping to develop collector systems in which networks of lower-capacity transmission lines would link several wind farms to a central point where they would connect to the main transmission corridors.
“My staff calls this our moon shot,” said Jones, who paraphrased President John F. Kennedy’s 1962 Rice University speech about landing a man on the moon: “We do it not because it is easy, but because it is hard.”
Reynolds said new lines should be built only if they help deploy wind and solar projects.
“With nearly 4,000 MW of new renewable energy projects proposed, real progress toward New York’s 50-by-30 goal is in sight,” Reynolds said in a statement. “New transmission capability is needed, but with upstate New York turning to a renewable energy future, the state should only be investing in those lines that are needed to deliver wind- and solar-generated power.”
WESTBOROUGH, Mass. — The challenge of preserving competitive markets while decarbonizing the New England economy was much on the minds of attendees at the Northeast Energy and Commerce Association’s 15th Power Markets Conference last week.
Some stakeholders fear New England states’ plans to procure up to 2,000 MW of renewable capacity could suppress prices in ISO-NE’s Forward Capacity Auctions. Those fears have receded somewhat, as the states are currently in negotiations for no more than 460 MW. (See New England States Move Toward Renewables Contracts.)
“The short-term problem isn’t as big as what was expected,” Jeff Bentz, director of analysis at the New England States Committee on Electricity, said during a panel discussion on the New England Power Pool’s Integrating Markets and Public Policy (IMAPP) process. “That level is pretty small and could enter in FCA 12 [2021/22] but probably won’t enter until FCA 13 [2022/23].”
Another panelist, Peter Fuller, vice president of market and regulatory affairs at NRG Energy, described his company’s proposed two-step auction to accommodate state policy resources while maintaining efficient pricing for merchant generators.
The first auction would reflect the market without the effect of subsidized resources. which would be paid to all generating resources clearing in the first step. A second, lower price including the subsidized capacity would be paid to the generating resources that are subsidized by state policy.
All resources cleared in both steps would receive a capacity obligation, but these obligations would be pro-rated to ensure that the total quantity of generation purchased is no greater than the status quo, ‘merchant’ outcome. NRG says this would ensure that the cost impact of the states’ policy actions is shared among all market suppliers equitably.
“While NRG supports including state policy-subsidized generating resources in the markets, t wholesale sellers and the private investors in the market should not have to shoulder the entire burden of all of the state policy objectives,” Fuller said. “And effectively that’s the world we’re in right now. The [ISO-NE] renewable technology resource exemption, while limited, does create a price-suppression effect and potentially puts the full cost of adding those resources on the backs of all resources in the markets.”
Bill Berg, vice president of wholesale market development at Exelon, said the IMAPP meetings instead need to determine what subsidized resources are able to bid into the FCA and which aren’t. An estimated 8.7 GW of nameplate clean energy generation capacity will be needed to meet the states’ 2030 goals.
“We’re talking about 8.7 GW of subsidized capacity. Think about the angst that 200 MW has caused. Think about trying to design a market that puts both objectives, allowing the states to do what they want and protect reliability and the market, when you’re dealing with an 8.7-GW spread, which is 25% of the [FCA] market,” he said.
Pallas LeeVanSchaick, vice president of Potomac Economics, the ISO-NE External Market Monitor, said there are inherent risks in the adoption of out-of-market contracts intended to achieve public policy objectives.
“We’re going to get to the point that contracts with individual resources may not pass on costs in the short term, except that they’re able to fund those priorities through lower wholesale prices,” he said. “Maybe in the short term we don’t see higher rates to consumers, but in the long term, I bet we will see legacy costs that go on long after the impacts on the lower wholesale prices end. We’re going to notice over time that these are not in the interests of consumers.”
On a panel on the opportunities presented by energy storage, Ian Springsteel, director of U.S. regulatory strategy for National Grid, likened the industry to how consumers might have reacted to a smart phone a decade ago. It has seemingly unlimited potential, but the industry and public aren’t quite sure what the device can do or how to integrate it into daily practices.
“We’re in the same place with storage. We have an inkling of what it can do as one of many tools in the energy market or the distribution system. But to integrate it into all the rules and operational framework, to fully use this technology, we’re at the beginning of that process,” he said.
Christopher Parent, director of market development at ISO-NE, said the RTO is comfortable with storage, having had decades of experience with pumped hydro in New England. ISO-NE currently has about 90 MW of storage in its interconnection queue. The queue has a total of 10,000 MW of resources, many from flexible fast-start gas generators.
“When we look at our 2025 [projections], we’re looking at 4,400 MW of wind and about 3,300 MW of solar on the system,” Parent said. “That creates a lot of variability on the system that shows annual summer peaks of about 25,000 to 28,000 MW. That’s going to create a need for a lot of flexible resources on the system, be it storage or whatever technologies materialize in the coming years. The key thing in the market is to send the right price signals so we get the response we need.”
MISO has filed with FERC its proposal to implement a separate three-year forward capacity market with a downward-sloping demand curve for its retail-choice areas.
The nearly 1,700-page filing, submitted Nov. 1, creates Tariff Module E-3 and makes corresponding changes to modules A, D and E-1 (ER17-284). Jeff Bladen, MISO executive director of market services, said the RTO took pains to incorporate stakeholder advice into the proposal over the 20-month period since the initial issues statement.
“The proposal is a reflection of the breadth of advice we got throughout the process,” Bladen said during a conference call after the filing. “There are no surprises in what we filed this afternoon. … We look forward to the review process FERC will undertake.”
The filing came despite calls from some stakeholders for more discussion. Bladen said that although all stakeholders didn’t agree on MISO’s forward auction solution, virtually all stakeholders agree that a problem exists that needs to be corrected. Bladen pointed to the OMS-MISO Survey that found a possibility of a generation shortfall below the RTO’s minimum reserve margin requirement in 2018. (See OMS-MISO Survey: Generation Shortfall Possible.)
MISO’s plan is designed to “ensure conditions don’t deteriorate further,” Bladen said.
“It’s no secret that there has been difference in opinion about the preferred approach,” he said.
Bladen said the proposal is designed to provide equally valued capacity from both merchant generators and regulated utilities. An analysis from The Brattle Group has demonstrated that the proposal would ensure enough capacity to meet reserve margins.
MISO is requesting an effective date of March 1, 2017, the beginning of its implementation timeline for the 2018/19 planning year capacity auction. He would not speculate as to what the RTO might do if FERC doesn’t approve the changes by then. “There are many plausible ways FERC might act, so there are too many hypotheticals,” he said.
To respect state jurisdiction, the filing includes a prevailing state compensation mechanism modeled after one in PJM that will provide an alternative method for demonstrating long-term resource adequacy outside of the forward auction.
Under the mechanism, state regulators can facilitate settlements of compensation rates between their load-serving entities and suppliers outside of MISO’s processes. Authorities must notify MISO of the amount of demand under such agreements two months prior to the auction.
The California Public Utilities Commission is protesting FERC’s decision to allow Pacific Gas and Electric to include a 50-basis-point ISO participation adder in its 2017 transmission rates proposal.
The CPUC said that the commission’s ruling “ignores the need to demonstrate that an incentive must be ‘justified’ pursuant to [FERC] Order 679,” which allows transmission owners to collect the adder as motivation to join an RTO.
The Sacramento Municipal Utility District (SMUD) joined the CPUC’s request that the commission reconsider its Sept. 30 order granting the adder, which the CPUC contends will provide PG&E an annual $30 million “unjustified windfall” at the expense of its ratepayers (ER16-2320). As a transmission customer of CAISO, SMUD uses part of the PG&E system to serve its own load and is subject to any rate changes.
Pacific Gas & Electric Transmission Lines | PG&E
While the commission’s Sept. 30 order accepted and then suspended PG&E’s request for a 10.9% return on equity based on concerns that the proposed rate adjustment could produce “substantially excessive revenues,” it denied a CPUC request to disallow the incentive adder. (See FERC Sets PG&E Rate Increase Proposal for Talks.)
The CPUC argued that California law requires PG&E — as well as the state’s other investor-owned utilities — to maintain membership in CAISO, invalidating the need for a financial incentive. Furthermore, justification for the adder is the subject of an ongoing proceeding before the 9th U.S. Circuit Court of Appeals, the CPUC noted.
FERC countered in its September order that the court challenge “does not operate as a stay of the commission’s consideration” of the issues.
In its Oct. 31 rehearing request, the CPUC pointed out that the commission has granted the adder to nearly every utility that has asked for it since it was implemented almost 10 years ago — including PG&E. The PUC has four times sought rehearing on the issue, but in each instance it withdrew the requests as a condition of a settlement.
“Faced with rapidly escalating transmission access charges, with no end in sight, the CPUC, and the California ratepayers who the CPUC represents, can no longer afford to let the FERC orders, which grant unjustified ROE incentives to California utilities for doing something they are already required to do, go unchallenged,” the CPUC wrote.
The CPUC estimates that the adder has so far cost PG&E ratepayers $125 million.
SMUD previously disputed the appropriateness of the adder and questioned whether it furthers California or FERC objectives with respect to the cost-benefits of ISO membership for PG&E customers. Like the CPUC, SMUD asked the commission to defer action on the incentive until the 9th Circuit’s decision.
FERC has scheduled a Feb. 7-8, 2017, settlement conference to address PG&E’s 2017 rate proposal.
FERC on Tuesday cast shade on an attempt by environmentalists and solar proponents to block NorthWestern Energy from cutting the prices for solar qualifying facilities in Montana.
But the commission’s procedural ruling didn’t address the merits of complaints that Montana regulators are attempting to discourage solar developers — a claim it will address in a separate docket.
The complaints were filed in response to the Montana Public Service Commission’s 3-2 ruling in June to suspend NorthWestern’s tariff for solar QFs larger than 100 kW under the Public Utility Regulatory Policies Act pending an updated rate review.
The commission acted after the utility sought emergency action, saying it feared a “flood” of QF filings because the rate — set in 2013 at $53.14/MWh (off-peak) and $92.37/MWh (on-peak) — was now 35% above its avoided costs (Docket No. D2016.5.39).
The change put about 130 MW of planned solar facilities in Montana in limbo. While the commission said solar projects could negotiate rates with NorthWestern while the review is pending, developers say they have no leverage and would be forced to accept the utility’s avoided cost figure.
FERC dismissed a complaint by the Vote Solar Initiative and the Montana Environmental Information Center, saying the PSC is not subject to the general complaint jurisdiction under Section 306 of the Federal Power Act and that the plaintiffs had no standing to file a complaint seeking PURPA enforcement (EL16-117).
“The Montana commission is not an entity that, for purposes of enforcement, [FERC] may, by order, require to take or not take particular actions,” FERC said. “Additionally, Vote Solar is neither a QF nor an electric utility, and as such is not authorized to file a petition for enforcement pursuant to Section 210(h) of PURPA.”
Jenny Harbine, an attorney with Earthjustice, which represented the complainants, called the decision disappointing. “It limits the ability for advocacy groups — including consumer advocates as well as clean energy advocates — to raise issues before FERC that are critical to the future of clean energy development and consumer choice,” she said.
Second Case Pending
But Harbine said the groups would participate as intervenors in a PURPA enforcement petition filed last month by FLS Energy, a North Carolina-based solar developer.
FLS said the Montana PSC’s actions “precluded [it] from continuing with the development of 14 advanced-stage solar QFs” and faces the loss of more than $750,000 that it has invested (EL17-5). The company said the order eliminated NorthWestern’s only PURPA tariff allowing for fixed, long-term payments for solar, which it called an “essential element of a financeable” power purchase agreement.
FLS Solar’s Fairmont Solar Farm in Fairmont, NC | FLS Solar
The developer said the commission’s order — which followed a hearing in which only the utility gave testimony and was not subjected to cross examination — is intended to discourage the development of small solar QFs.
“The Montana PSC performed a back-of-the-envelope calculation and suspended the rates based on an initial conclusion (untested by discovery or opposing testimony),” FLS said.
It said the commissioners’ “hostility towards the goals of PURPA is evident from statements made by a majority of the commissioners” at hearings in the NorthWestern case and in an editorial by Commissioner Brad Johnson, who accused solar developers of using PURPA to finance projects, “cherry picking the states with the highest government-assured rate to do business in.”
“Simply put, it was well past time to put the rate on pause and update it again,” Johnson said, noting that the Montana Consumer Counsel supported NorthWestern’s request for the suspension.
Dissent
In his dissent, Commissioner Travis Kavulla accused his colleagues of flouting the commission’s procedures and precedents.
“The intervention deadline to the proceeding occurred only after a hearing on NorthWestern’s motion was held. Certain parties — or rather, quasi-parties, since the intervention deadline had not arrived — participated in that hearing, but the developers of the projects that would be compensated under the rate schedule did not,” wrote Kavulla, the current president of the National Association of Regulatory Utility Commissioners. “The hearing commenced with the purpose of taking ‘argument’ on NorthWestern’s motion. Then, as a surprise to those in attendance, counsel for NorthWestern alerted the commission that it also wished to offer evidence. No other quasi-party presented evidence at this hearing.”
On Wednesday, FERC granted Montana regulators’ request for more time to respond to the petition, extending the deadline until Nov. 17.
Other States
Utilities in other states also are trying to limit PURPA payouts. Idaho, for instance, has limited such solar QF contracts to two years only in a 2015 ruling. Duke Energy is contemplating a similar move against solar QF rates in North Carolina, according to Vote Solar.
American Electric Power CEO Nick Akins hardly sounded like someone whose company had just taken a $2.3 billion impairment Tuesday, telling investors and analysts he is “very happy with the strategic process” and that “conditions are in place that are conducive to us achieving our objectives.”
Akins’ comments came as he led a panel of AEP executives briefing investors and analysts in New York following the company’s third-quarter earnings release. With the one-time charge, AEP posted a loss of $765.8 million (-$1.56/share) for the quarter, compared with a profit of $518.3 million ($1.06/share) for 2015’s third quarter. Sales were up from $4.4 billion to $4.7 billion, partly because of a warm summer.
“The new story of AEP is one of higher growth, higher dividends, more regulation and more certainty,” Akins said. “When you stop chasing the wrong things, you give the right things the chance to catch you.”
Lower Rio Grande Valley Transmission Project | AEP
The impairment reflects AEP’s ownership share of 2,684 MW of competitive generation in Ohio, including its Cardinal, Conesville, Stuart and Zimmer plants. It also includes the competitive portion of the coal-fired Oklaunion Plant in West Texas, the Desert Sky and Trent Mesa wind farms, also in West Texas, and some coal-related properties.
Akins said the company will spend $17.3 billion in capital investments through 2019 — $9 billion on transmission — an increase of $4.3 billion from plans laid out last year through 2018. The company owns the largest transmission system in the U.S., with 40,000 miles of lines and more 765-kV extra-high voltage than all other transmission systems combined.
“We’re focusing the proceeds on the [transmission business] we find attractive,” said Akins, who noted AEP already accounts for 14% of the country’s transmission investment. “We’re able to invest in transmission in an order of magnitude not many others have. If you’re looking for a transmission company, AEP is certainly that. We’re well-positioned as a regulatory business.”
The company also plans to increase its renewables through long-term power purchase agreements. AEP expects to add 5,400 MW of wind energy and 3,400 MW of solar power through 2033.
| AEP
Investors didn’t respond positively to the news. AEP shares closed Wednesday at $62.61/share, down 77 cents (-1.21%) on the day.
AEP’s embrace of regulation also allows it to escape the problems it faces in Ohio’s competitive-generation market. Many of the company’s coal plants date back to the 1970s and earlier, making them underperformers against other power units. Coal resources accounted for 71% of AEP’s generation in 2005, but that figure is projected to drop to 47% next year.
“Fortunately, AEP’s balance sheet can withstand this impairment,” CFO Brian Tierney said. “Combined with other sales of generating assets, it puts the Ohio generation debacle behind us. We also have wires companies in the states with very attractive returns.”
Akins said AEP would continue working with legislators to restructure the Ohio market.
Both AEP and FirstEnergy attempted to get relief from the Public Utilities Commission of Ohio with what amounted to a subsidy request for their competitive generation. While what opponents called a “bailout” was approved by PUCO, FERC effectively scotched the deals, saying they needed to undergo a more stringent review.
AEP decided to work to get favorable reregulation legislation approved.
But FirstEnergy — which reported a $1.1 billion loss in the second quarter, much of it related to the closure of five coal-fired units — filed a modified request with PUCO seeking a $558 million-a-year rate stability rider for eight years.
In October, PUCO voted instead to give the company $204 million a year for only three years. FirstEnergy has until Nov. 11 to file for a rehearing on the order, which it called “disappointing.” (See PUCO Rejects FirstEnergy’s $558M Rider, OKs $132.5M.)
