MISO and PJM could terminate or suspend pseudo-ties that no longer satisfy agreed-upon requirements under a joint proposal.
The RTOs’ proposal also includes a provision that would make each of them the native reliability coordinator for units pseudo-tied into the other balancing authority area, “responsible for transmission-related congestion on the transmission system where the pseudo-tied units are physically connected.”
The RTOs are adding coordinated pseudo-tie policies to their joint operating agreement. MISO last week released a first draft for stakeholder review.
The proposed rules also stipulate that pseudo-tied units must follow both PJM and MISO modeling procedures and obtain station service according to native balancing authority rules. They also make clear that pseudo-tied units committed as capacity resources in a delivery year cannot be directed to serve load in the native balancing authority when the attaining balancing authority requires the unit’s output — unless they are needed to avoid exceeding NERC operating limits in the native balancing authority. The RTOs also agree that only pseudo-tied units — and not the RTOs — are responsible for compensating an attaining balancing authority for failure to deliver energy.
“There were some common-sense coordination practices to add to the joint operating agreement,” MISO Senior Director of Regional Operations David Zwergel said during a June 29 Reliability Subcommittee call. He said MISO and PJM staff collaborated to come up with the proposed rules.
Zwergel said the RTOs expect to file the agreement changes with FERC in late July and asked stakeholders to submit written comments on the draft language by July 13. PJM is also reviewing the language with its own stakeholders, he noted.
The joint effort stems from two FERC deficiency letters in response to the RTOs’ separate attempts to implement more stringent rules in order to improve control over an increasing number of pseudo-ties between MISO and PJM. The letters asked both MISO and PJM to explain efforts they undertook to work with each other in developing the rules. (See MISO, PJM to Try Again on FERC Pseudo-Tie Filings.)
Both RTOs have said they plan to refile different versions of the stricter pseudo-tie rules. MISO initially said that adding standard pseudo-tie rules in the RTOs’ joint operating agreement was unnecessary but changed course earlier this year. It also recently asked FERC to schedule a technical conference to clarify the rules governing the implementation and use of pseudo-ties. (See MISO Asks FERC for Pseudo-Tie Technical Conference.)
During last week’s call, Entergy’s Jennifer Amerkhail asked why the RTOs also included rules governing “partial” pseudo-ties — an arrangement that accommodates generators that supply both RTOs.
Zwergel responded that earlier this year a MISO partial pseudo-tied resource failed to follow dispatch orders and overproduced on one side of the seam. The proposed rules expressly state that the portion of the generation dedicated to supplying the attaining balancing authority must follow its instructions, while the remaining generation must follow native balancing authority rules and dispatch.
Other stakeholders asked why the RTOs would include a requirement for 42-month written notice in advance of terminating a pseudo-tie.
Zwergel said the requirement is based on a six-month advance in addition to PJM’s three-year forward capacity auction. While the notice is unnecessarily long for MISO, it is necessary to accommodate the RTOs’ disparate capacity auction schedules, he said.
POUGHKEEPSIE, N.Y. — Capital markets this year are more willing than ever to finance green energy projects, said a panel at the Renewable Energy Conference last week.
“None of the terms have changed; the deals haven’t changed. What’s changed is banks’ appetite for renewables, and they’re willing to price down and move in on these deals,” said Denis O’Meara, managing director of energy and natural resources at BNP Paribas, who sat on a panel on renewable project financing.
The Business Council of New York State and the Hudson Renewable Energy Institute hosted the event at Marist College Wednesday.
“If you have a project and the project has merit, it’s going to get financed,” said panel moderator Scott Medla, managing partner at Ansonia Partners. “The institutional investors, the private equity guys, the banks — they have more money than they could possibly ever use to fund every project in America. The issue for them is finding the right project, the one that fits.”
Caroline Angoorly sat on the panel as COO of the New York Green Bank, a billion-dollar fund supported by ratepayers and part of the state’s $5.3 billion Clean Energy Fund.
“The idea of New York Green Bank is to play in what we call that one standard deviation, on either side of where current energy project financing markets play,” Angoorly said. “As these new energy models get new traction [and] become more ubiquitous, [we] provide liquidity when traditional sources of capital may not be ready.”
Medla said that significant improvements in technology are helping drive banks’ interest in financing green projects.
“We’re seeing tremendous advances in creativity around transmission lines. We’re seeing wonderful things happen in the area of storage,” Medla said. “My view is that the lithium-ion batteries … are going to get surpassed pretty quickly with some of the creativity that I see out on the margin.”
Wind projects in New York are more difficult to finance than in other parts of the country, according to O’Meara. “The reason is wind regimes and terrain, so you have to be very specific and you have to have very good wind studies to be able to build a wind turbine or wind farm here. … We’ll go up to 15 years in financing, maybe even longer depending on the [power purchase agreement]. … I’m telling you that because those are really pretty aggressive terms that we’re seeing out there in the market right now.”
Finance pricing now ranges between 1.35 and 1.75 percentage points more than the LIBOR, which O’Meara called attractive terms.
“The variable between the spreads really go to sponsor, technology, capital in, how much you’ve done — we’re going to look at all that when we make that determination of [if] we go ahead and finance,” O’Meara said.
BNP also does bond financing on wind, which tends to be a bit more lenient in its terms.
“You get a longer tenor [loan term] — sometimes less debt — but longer tenor, so you can put the deal to bed,” O’Meara said. “Solar’s more predictable: You know what it’s going to be on each season, and it works out more easily for us to think through a solar financing. Banks will go pretty long on solar as well, construction plus 18 or 20 years.”
Community Power
Angoorly cited the Green Bank’s $600 million pipeline of coming projects, including storage and microgrids, the latter supported by “a lot of pent-up demand for community-aggregated generation.”
O’Meara said he had similar experience with what is called community choice aggregation in California.
“In Marin County, they wanted to do this,” he said. “It’s a very good idea but really hard to bank at this point. … It’s not standardized. Many times I would call it the commune of power, because these people are putting these deals together and I have no idea what they’re saying. … I don’t know where they wrote it — probably in a coffee house — but it did not make sense.”
But fuzzy contracts haven’t stopped projects from moving forward.
“In fact, they’re getting the off-takers and the off-takers want to finance this,” O’Meara said. “It’s an evolving market. I guarantee you it will move into a more commercial purview shortly, but it’s not there now.”
Massachusetts officials said Friday the state’s electric distribution utilities must procure a combined 200 MWh of energy storage by Jan. 1, 2020 — an unambitious goal to some observers.
Although the Department of Energy Resources’ (DOER) announcement called the 200 MWh “an aspirational” target, some industry stakeholders expected more from Gov. Charlie Baker’s Energy Storage Initiative. The department’s State of Charge report, released in September, presented recommendations for generating 600 MW of advanced energy storage by 2025, saying it would capture $800 million in system benefits. (See Mass. Considering Storage Mandate.)
| DOE Global Energy Storage database and Massachusetts Department of Energy Resources
“Based on lessons learned from this initial target, DOER may determine whether to set additional procurement targets beyond Jan. 1, 2020,” DOER Commissioner Judith Judson said in announcing the target. The state also agreed to spend $10 million on energy storage demonstration projects in addition to the $10 million that accompanied the ESI announcement in May 2015.
Judson said the state also had begun implementing other recommendations from the State of Charge report, allowing storage to be paired with the state’s plans to procure 9.45 million MWh of clean energy and 1,600 MW of offshore wind.
She also said the state was “incentivizing” storage through the Solar Massachusetts Renewable Target (SMART) program and that storage would be funded by alternative compliance payments under the ACES Grant Program, the Peak Demand Reduction Grant Program and the Community Clean Energy Resiliency Initiative, and that storage would be eligible for future Green Communities grants.
| Massachusetts Department of Energy Resources, Massachusetts Clean Energy Center
It also is considering allowing utilities to use energy-efficiency funds for storage that provides sustainable peak load reductions and expanding energy storage in the Alternative Energy Portfolio Standard.
“It’s less of an aspirational target, something the state’s going to strive for, and more a description of what the state is already doing,” said Ted Ko, director of policy at Stem, a provider of commercial-scale energy storage. “It’s entirely possible they would have met [the target] anyway. For example, Eversource [Energy] has already proposed over 180 MWh of storage projects in a recent rate case.”
Ko said the SMART program, whose regulations were released last month, “by itself conceivably could come up with 100 MWh.”
“Essentially, by setting a low, voluntary target number, you’re not inspiring any new programs or new initiatives as outlined in the State of the Charge report,” he added.
The announcement drew similar, if more temperate, comments from others, including Chris Rauscher, director of public policy at residential solar company Sunrun.
“The decision by DOER to set a soft energy storage target of 200 MWh is a moderate first step in providing long-term market surety,” Rauscher said. “Growing the storage market in Massachusetts has the potential to support local job creation and lower costs for Massachusetts ratepayers, all while providing critical resiliency through backup power.”
Rauscher said the company would work with legislators to expand storage’s potential “by encouraging private investment in Massachusetts through programs like the Alternative Energy Portfolio Standard.”
The Energy Storage Association noted that Massachusetts utilities previously proposed “specific, albeit voluntary, procurement targets of a combination of up to 200 MW/500 MWh of energy storage. Today’s announcement is a more conservative step in that direction.
“Massachusetts is also competing for industry jobs with California, Oregon, New York and other states moving forward on their own storage procurement targets,” ESA added.
Massachusetts becomes the second state in the U.S. to mandate storage. The California Public Utilities Commission in 2013 ordered the state’s three large investor-owned utilities to add 1.3 GW of energy storage by 2020.
New York lawmakers last month passed a measure requiring the state’s Public Service Commission to set targets to increase the adoption of energy storage in the state through 2030. If signed by Gov. Andrew Cuomo, the new law would require the commission to work with the New York State Energy and Research Development Agency and the Long Island Power Authority to set up a storage deployment program. (See NY Bill Sets Stage for Storage Targets.)
HERSHEY, Pa. — Near the end of the final panel at last week’s Mid-Atlantic Conference of Regulatory Utilities Commissioners conference, PJM’s Stu Bresler was asked what it would take for the RTO to take the lead on developing a large-scale, regional transmission line from Virginia to New York City to help take advantage of offshore wind capabilities in the Atlantic Ocean.
“My knee-jerk, flippant answer is a whole lot of money,” said Bresler, PJM’s senior vice president of markets and operations. “It’s difficult at this point to build a reliability case for that kind of infrastructure investment. I think what’s required is more a business case for the generation to say that level of investment is rational.”
PJM would know. Every month, a heated debate flares up at its Transmission Expansion Advisory Committee meetings to examine the details, costs and necessity of proposed transmission projects. American Municipal Power’s Ed Tatum often leads the discussion.
As a member of a panel on transmission replacement earlier at the conference, Tatum revealed that when he was brought on at AMP, he was given a mission to reduce its members’ transmission costs. He responded that controlling their costs would be a more reasonable goal.
That could be because much of the transmission grid needs replacement, and transmission owners are often sensitive to any implication they’re overbuilding the system. Tatum’s fellow panel participant, Jodi Moskowitz of Public Service Electric and Gas, took exception to that suggestion in her opening remarks.
“We don’t look at the issue quite that way, in terms of if the transmission system is overbuilt,” Moskowitz said. “We think that the appropriate focus is to make sure that we have a safe, reliable grid for many years to come, but make sure we are planning and building in a cost-effective way.”
And even that might be more expensive than customers want to pay. Speaking on the fuel mix panel with Bresler, Rich Sedano of the Regulatory Assistance Project said the one-day-in-10-years loss-of-load expectation that PJM and other grid operators use is a handy standard, but not necessarily indicative of what the market will bear.
That clash over cost versus demand would be cleared up through increased competition and cost-containment measures in transmission construction, LS Power’s Sharon Segner said. “If you read the [court] orders on why competition was upheld, it’s because of the argument for the consumer benefits of competition.”
While Segner said that cost containment offers price assurance, Moskowitz cautioned that there will always be “uncontrollable issues” that occur during construction.
Expressing the states’ perspective, West Virginia Public Service Commissioner Brooks McCabe called for restraint on all sides. During the transmission panel, he urged slowing down the decisions to construct large-scale projects and to revisit the “fundamental ground rules” to “tweak” when and how projects should be addressed.
On the fuel mix panel, he urged everyone to “lighten up” because the “hard work” would not be solved immediately. Retaining baseload units is important, he said, because “that’s our security blanket.”
Matt Crozat of the Nuclear Energy Institute had a mixed reaction to that message. He said he can’t be relaxed like McCabe because “I know that if I lose nuclear plants, I can’t get them back.”
By Michael Kuser, Amanda Durish Cook and Rich Heidorn Jr.
Following FERC’s two-day technical conference on tensions between wholesale electric markets and state energy policy initiatives in early May, the commission invited comments on five potential paths forward (AD17-11).
The paths include a continuation of the status quo (Path 3), with the courts sorting out whether state initiatives — such as the zero-emission credits for Exelon nuclear plants in New York and Illinois — violate federal jurisdiction; changes to the minimum offer price rule (MOPR) (Paths 1 and 5); and market rule changes to accommodate state policies (Path 2) or incorporate them into RTO and ISO pricing (Path 4).
The commission also asked commenters to rate the urgency of the issue and solicited suggestions on how FERC should go forward procedurally.
More than 80 commenters responded, although many repeated their past positions and did not provide feedback on the paths the commission outlined. Based on RTO Insider’s review of the comments, below is a summary of the supporters and detractors of each path.
Paths 2 and 4 appeared to be the most popular, although there were supporters and detractors for all of the proposals.
The range of challenges to the capacity market constructs in PJM, ISO-NE and NYISO — the Eastern markets that were the focus of the technical conference — raises the prospect that FERC could relax the markets’ participation requirements. Public power advocates, who have been seeking relief for years, peppered their comments with repeated demands to let them acquire capacity via bilateral contracts, with capacity auctions playing a much smaller, “residual” role.
Path 1: Limited or No Minimum Offer Price Rule
FERC Description
“An approach that would either not apply the minimum offer price rule to state-supported resources, or limit application of the minimum offer price rule to only state-supported resources where federal law pre-empts the state action providing that support.”
Background
If FERC were to abandon the MOPR altogether, it would likely invite court challenges alleging it was allowing states to usurp its authority under the Federal Power Act. Thus any relaxation of MOPR is likely to be constrained by the Supreme Court’s 2016 rulings in Hughes v. Talen and Electric Power Supply Association v. FERC. (See Court’s Reticence Frustrates Energy Bar.)
Supporters
Load-serving entities are the biggest fans of this approach, which also is supported by the Nuclear Energy Institute (NEI) and some commenters in the renewables camp.
The National Rural Electric Cooperative Association (NRECA), American Municipal Power and Old Dominion Electric Cooperative support Path 1 or 2 or a combination of the two.
The American Public Power Association (APPA) called for “a greatly limited MOPR that provides full exemptions for self-supply and state-sponsored resources, or the ability to remove such resources from the capacity market clearing process altogether.”
The Transmission Access Policy Study Group (TAPS), which represents transmission-dependent utilities in 35 states, considers it “potentially viable.”
NEI, the Sierra Club and the Natural Resources Defense Council’s Sustainable FERC Project all expressed support, with NRDC calling it the solution “most likely to support proper price formation.”
Opposed
Groups representing consumers led the opposition, with the Electricity Consumers Resource Council (ELCON) rejecting it as “too extreme.”
A group of 60 large industrial, commercial and institutional energy consumers in New York who filed as “Multiple Intervenors” also opposed it, saying “it presumes that state public policies that unduly impact or interfere with competitive wholesale electricity markets must be accommodated in most circumstances, and that the preferred ‘solution’ in cases where federal law pre-empts state action is the application of a minimum offer price rule.”
“While MOPRs may be appropriate in certain circumstances, Multiple Intervenors disagrees that they represent the only — or even the best — response to all state public policies that trespass into the commission’s jurisdiction,” the group said.
NRG Energy also opposed Path 1, saying it would exacerbate price suppression in wholesale markets by allowing subsidized resources to enter the markets at prices below actual cost. It has proposed a “Forward Clean Attribute Market” in the New England Power Pool’s Integrating Markets and Public Policy (IMAPP) initiative.
NRG, Dynegy, Eastern Generation and the Electric Power Supply Association (EPSA) filed a federal court suit in October claiming the New York ZECs intrude on FERC’s jurisdiction over interstate electricity transactions. The same companies filed suit in February challenging Illinois’ ZECs for Exelon’s Quad Cities and Clinton nuclear plants and have also asked FERC to reject the subsidies.
Path 2: Accommodation of State Actions
FERC Description
“An approach that would accommodate state policies that provide out-of-market support with the operation of the wholesale markets by allowing state-supported resources to participate in those markets and, when relevant, obtain capacity supply obligations, subject to adjustments necessary to maintain certain wholesale market prices consistent with the market results that would have been produced had those resources not been state-supported.”
Background
Proposals for two-tiered capacity auctions that would clear subsidized resources separately fall into this path.
LSEs are the biggest supporters, with the NRECA, AMP, ODEC and Eastern Massachusetts Consumer-Owned Systems backing the concept. The American Forest and Paper Association also favored a Path 2 solution, saying “each of the other four pathways are likely to prove impractical and more expensive for consumers.”
APPA said it supports efforts to accommodate state actions, “assuming such accommodation also covers resources procured by public power and cooperative utilities. Such an accommodation should be designed broadly so that there is no determination by the RTO of what constitutes ‘legitimate’ state policies.”
The New England States Committee on Electricity (NESCOE) noted that NEPOOL’s IMAPP initiative “has focused on developing approaches that align with Paths 2 and 4.” At the conference, ISO-NE presented its proposal for a two-tiered auction that it said would incorporate state-mandated renewable generation while preventing oversupply and addressing objections to a regional carbon tax. (See ISO-NE Two-Tier Auction Proposal Gets FERC Airing.)
The Advanced Energy Management Alliance (AEMA) said FERC should direct ISO-NE, NYISO and PJM to file Path 2-type changes in capacity market rules to support “the rights of states to control their own energy policy and to procure carbon-free resources that wholesale markets can integrate cost-effectively” while ensuring they do not distort wholesale prices.
New York City said Paths 2 and 4 provide the “best opportunities to correct current market constraints” on renewable resources and new technologies procured under public policy goals.
“The appropriate future is clearly a combination of Paths 2, 4 and 5,” NRG said, adding that they are consistent with a “pro-markets approach [that] appears to have wide support from across the stakeholder community.”
Independent power producers Calpine and Dynegy also expressed support for Path 2, with Calpine calling it a “mid-term solution.” Dynegy says Path 2 “is the next step: a robust stakeholder process to fully develop and refine the proposed solutions that have recently been presented by the ISOs/RTOs (ISO-NE’s Competitive Auctions with Subsidized Policy Resources (‘CASPR’) proposal and PJM’s capacity market repricing proposal).”
Brookfield Renewable, the Conservation Law Foundation and NextEra Energy, which are promoting their Carbon-Linked Incentive for Policy Resources (CLIPR) proposal as a long-term Path 4 solution, say Path 2 may be needed in the interim.
“Feasible Path 4 solutions — like the CLIPR proposal — must be identified simultaneously with the formulation of any interim short-term proposal, as doing so will avoid the risk that the interim Path 2 solution outlives its useful life to the detriment of the market and more robust and comprehensive long-term solutions,” the “CLIPR Coalition” said.
Avangrid said a combination of Paths 2 and 3 is best for multi-state regions, “while Path 4 is better suited to single-state wholesale markets.”
Opposed
ELCON and New York’s Multiple Intervenors opposed, with ELCON rejecting it as a “kluge.”
PJM’s Independent Market Monitor, which opposed all but Paths 4 and 5, said “it would be a mistake for ISO/RTOs to explicitly accommodate state-level subsidies” in their capacity market design.
The American Wind Energy Association said any Path 2 solution should be “technology-neutral.” It questioned “the feasibility of any Path 2 solution that proposes to differentiate … ‘subsidized’ resources from ‘unsubsidized’ resources and calculate the competitive offer price of the ‘subsidized’ resources.”
The New York Public Service Commission, which is backing a plan to integrate carbon pricing into the NYISO market, said Path 2 “illustrates the limitations of the five paths.”
Path 3: Status Quo
FERC Description
“An approach that would rely on existing tariff provisions applying the minimum offer price rule to some state-supported resources, and continuing case-by-case litigation over the specific line to be drawn between categories of state actions that may, or may not, result in a state-supported resource being subject to the minimum offer price rule.”
Background
At the hearing, acting FERC Chair Cheryl LaFleur urged stakeholders to avoid “unplanned and piecemeal regulation,” saying “it would be a bad outcome for customers and market participants in terms of cost, reliability and regulatory certainty.”
Few commenters embraced the status quo, although ELCON called it the only path that is “tenable.” Duke endorsed it, saying that stakeholder discussions occurring in the RTOs/ISOs “should run their course” and that it is not necessary for the commission to take “prescriptive” action. “Threshold legal issues are pending before the courts, and the resolution of these issues should be allowed to play out before any further action is taken at the federal level,” ELCON said.
The large New York customers group said that while it is “not optimal,” it “may be the most realistic among the choices identified” by FERC.
AWEA said it would support Path 3 only if FERC continues to exempt renewable resources from the MOPR.
Opposed
TAPS called it “unsustainable and unworkable,” and NRECA and APPA also opposed, with the latter saying, “No participants expressed support for this option at the technical conference.
“The lack of support for the status quo has persisted throughout the history of the capacity markets and must be recognized in determining future paths,” APPA said.
Dynegy’s Illinois Generation Assets | Dynegy
NRDC said Paths 3 and 5, “as well as some approaches to implementing Path 2,” would violate the Federal Power Act by improperly discriminating between resources. “The act of defining what is or is not a ‘subsidy’ will inevitably entail arbitrary and discriminatory line-drawing efforts, as has become increasingly clear through FERC’s decisions regarding the application of the MOPR to resources supported by state policies,” it said.
Dynegy said Path 3 is “unsustainable.”
“Dynegy has already been negatively impacted by the ZEC subsidy programs and will continue to be negatively impacted absent relief from the courts or commission action. In a ‘status quo’ scenario, Dynegy will be unable to proceed with capital improvements [and] hiring, and will need to evaluate shutdowns of generating plants that are more cost efficient than the subsidized nuclear units.”
Path 4: Pricing State Policy Choices
FERC Description
“An approach in which state policies, to the extent possible, would value the attributes (e.g., resilience) or externalities (e.g., carbon emissions) that states are targeting in a manner that can be readily integrated into the wholesale markets in a resource-neutral way. For those state policies that cannot be readily valued and integrated into the wholesale markets, Path 4 would also require consideration of what, if anything, the commission should do to address the market impacts of these state policies. For instance, other approaches for these state policies may include accommodation, application of the minimum offer price rule or an exemption from the minimum offer price rule.”
Background
A carbon price adder is one potential Path 4 solution, but it has been rejected by the New England states.
Supporters
The NYPSC said its work with NYISO to incorporate carbon into the wholesale electricity markets “might be viewed as an endorsement of Path 4.”
Path 4 also won support from Dominion Energy, Calpine, Dynegy, Exelon, NEI, Vitol and the Solar Energy Industries Association (SEIA).
EPSA gave Path 4 conditional support. “The challenge will be to define those resource attributes (e.g., flexibility) or externalities (e.g., carbon emissions) that should be integrated into the wholesale market, and then to develop a mechanism to value those qualities in a resource-neutral manner,” EPSA said, adding that it “is confident that, if these objectives can be identified, the ISOs/RTOs and market stakeholders can establish workable and efficient means to integrate these objectives into competitive market structures.”
APPA also gave a qualified endorsement, saying it could result in “an efficient means of achieving environmental or other policy goals if it were limited to a single price adjustment, such as a carbon tax or adder.” The group said it would only support this “achieve” approach “if it were done along with and not as a replacement to an accommodation of state policies or a move to a voluntary residual capacity market.”
AWEA said Path 4 is its first choice and would allow the markets to “better value the benefits and externalities of renewable energy that are not being currently captured.”
It also expressed concern that the five paths could tread on state sovereignty, asking FERC to consider carbon pricing. “Since there is currently no real conflict between state-supported renewable energy resources and wholesale markets, nor has there been one over the decades for which these policies have been in place, there is no basis for the commission to suddenly upset this balance by infringing upon state sovereignty and undoing the intent of state laws that seek to promote renewable energy.”
The Brookfield “CLPR Coalition” said Path 4 is preferable to Path 2. It asked FERC to issue a policy statement directing the RTOs to submit “achieve” solutions to the commission in the near term and requiring them to file quarterly reports on their progress.
Opposed
Opponents include the Natural Gas Supply Association, NRECA, TAPS and the large New York customers, the last of which said they were skeptical that it could be implemented effectively and benefit customers.
ELCON said the proposal would be the “most prone to abuse” of the alternatives. “It would fail in real-world conditions because some states would not respect market-based solutions. They would concoct attributes that are not realistically fungible or tradable for the purpose of selectively internalizing externalities or for socializing the costs of command-and-control mandates.”
AEMA said FERC should allow RTOs and stakeholders to develop solutions but not force them to file proposals. “Pricing state policy into energy and ancillary markets, through mechanisms such as carbon adders, raises several controversial issues. Capacity market solutions are not plagued with such controversial questions, and if the commission were to direct ISOs to pursue both capacity and energy market solutions simultaneously, it would slow the progress of the capacity market solution,” AEMA wrote.
Economist James F. Wilson said the commission should set a long-term goal “of seeing more revenues from the energy and ancillary services markets, and eventually phasing out the capacity constructs, or converting them to voluntary mechanisms, recognizing the changing nature of `resource adequacy.’
“The energy and ancillary services markets hold the potential to efficiently guide the changing resource mix over time, including incorporating public policy objectives such as decarbonization that presently are not reflected in the markets; the capacity constructs cannot do this,” Wilson continued. “Reducing the role of the capacity constructs will require resisting the frequent pressures to change them in ways that raise capacity prices and/or lead to clearing substantial excess capacity.”
Cliff Hamal, managing director of Navigant Economics, said “the most fundamental assumption” underlying capacity markets — setting capacity prices based on the cost of building new gas-fired generation — may no longer be valid. “What if policy options, such as those that promote low-carbon resources and demand reductions have eliminated the need for regular additions of gas-fired generation? A case could be made that we have already reached that point, or might do so in the near future. If so, the fundamental basis for setting capacity prices through the net-[cost of new entry]-based demand curve auction is no longer valid.”
Path 5: Expanded Minimum Offer Price Rule
FERC Description
“An approach that would minimize the impact of state-supported resources on wholesale market prices by expanding the existing scope of the minimum offer price rule to apply to both new and existing capacity resources that participate in the capacity market and receive state support.”
Background
The MOPR came up frequently at the technical conference with some witnesses calling for its expansion and others seeking its relaxation or abolition. (See Uncertain Future for MOPR.)
Supporters
EPSA and EPSA members Dynegy and Calpine would like to see this path pursued immediately, while the NGSA says it is fine as a short-term fix but not as a long-term solution. Calpine also sees it as a “near-term” fix.
Competitive Power Ventures called for expansion of the MOPR to reserve price signals, the implementation of a “universal” carbon price into the energy markets and RTO dispatch decisions and improvements to price formation.
Opposed
NRDC, which said it would not be just and reasonable, was joined in opposition by Hydro-Quebec, the New York Power Authority, NEI, Dominion, FirstEnergy, East Kentucky Power Authority, the New York Multiple Intervenors, the PJM Industrial Customer Coalition, ELCON, TAPS, NRECA and APPA.
APPA called it “the worst possible outcome,” which would result in “an overly administered noncompetitive market that would frustrate resource development pursuant to policy decisions.”
“This would greatly benefit the pure merchant facilities, leading to a significant decline in resource diversity, a higher cost of capital and a lack of any type of planning or optimization of resources. Because the states will likely continue to seek to procure or retain resources based on policy preferences, an expanded MOPR also increases the risk of overbuilding and double-payment for capacity.”
The Multiple Intervenors was also opposed, saying that MOPRs “have the effect of sheltering incumbent generation owners from competition and impeding market entry.”
AWEA said it could open “the door to widespread mitigation of legitimate state policies and, in turn, uncertainty for renewable energy investors.”
“If the commission approves a MOPR based on factors other than limiting the application of the MOPR to only state-supported resources where federal law pre-empts the state action, then it becomes difficult to draw a clear boundary limiting commission interventions,” AWEA said. “As this path has no discernable limit to what types of public policies would be exposed to a MOPR, it could lead to an environment where legitimate state renewable energy policies could be impeded by the risk of being mitigated.”
In a joint filing, AWEA, Advanced Energy Economy, Alliance for Clean Energy New York, American Council on Renewable Energy, Mid-Atlantic Renewable Energy Coalition, RENEW Northeast, and Wind on the Wires also opposed expanding MOPR.
“All energy resources benefit from subsidies and/or favorable policies and, therefore, a singular focus on incentives for certain resources such as renewables, would be discriminatory,” they said. “Contrary to the claims of some of the panelists at the technical conference, Northeast power systems are performing better as a result of the availability and integration of renewable energy into the resource mix. Negative pricing is rare and, more importantly, not responsible for negative economic impacts on other generation sources. Gas prices, not renewables, are the primary factor reducing revenues for nuclear, coal, and other supply sources.”
Economist James F. Wilson also opposed Path 5. “The markets are not nearly as fragile, and the impacts of public policy resources not nearly as substantial, as some stakeholders suggest,” he said.
Rob Gramlich of Grid Strategies said FERC should continue to treat public policies as “exogenous, as a factor that may affect market participants’ behavior and willingness to pay or accept money for a transaction, but not something for the commission to mitigate or undo. One can disagree with some of the laws state and federal legislatures pass, and FERC can offer its input into legislative processes, but it would be a major shift in the regulatory paradigm for the federal electricity market regulator to go beyond intervening to remedy market power and manipulation and enter the realm of mitigating public policy.”
“A wide range of state and federal policies have affected quantities and prices in power markets since the inception of U.S. electricity markets,” Gramlich continued. “For example, there might not be any nuclear generation in operation were it not for the Price-Anderson Act limiting liability for unit owners. We might not have as much natural gas generation if intangible drilling costs were not allowed to be deductible as a current business expense under federal tax law.”
NEI and IPPs — though on opposite sides of the nuclear subsidy debate — agreed on the need for a speedy resolution. NEI said RTO markets are not just and reasonable if they don’t provide sufficient revenues to retain nuclear generation threatened by low-cost natural gas.
EPSA said immediate action is needed to “insulate” wholesale markets “from current distortive state actions while all stakeholders collaborate on identifying market structures that help address defined public policy goals.” Also calling for urgency were Calpine, Eastern Generation, the Independent Power Producers of New York, the New England Power Generators Association, LS Power and NRG, which said that competitive markets are “under siege.”
NRG said FERC should actively participate in suits challenging the ZECs and act on pending complaints before the commission on the subject of the MOPR.
The R Street Institute, a free-market think tank, said FERC should have “an extremely high sense of urgency.”
Dynegy also called for swift action, criticizing Exelon Senior Vice President of Competitive Market Policy Kathleen Barron, who told FERC on May 1 that “we have some time to talk about where we go.”
No
Exelon responded that FERC should implement energy market fixes to eliminate the need for ZECs before considering any of the paths identified.
The PJM ICC said there was “no need for rush to judgment” and ELCON said the “problem at hand is too important to be rushed.”
NRDC said there is no evidence of a “crisis,” pointing out that reserve margins in PJM, ISO-NE and NYISO are all currently higher than their targets.
The Union of Concerned Scientists said the “proposed solutions are premature due to lack of [a] coherent argument” for action. “The calls for urgent action by stakeholders have presumed that there is clarity regarding the nature and size of the alleged problem with the capacity markets,” it said. “As far as the renewable portfolio standards, there is neither urgency, nor a clear statement sorting the issue.”
Procedural Steps
NRECA and Exelon said FERC should convene technical conferences in each region and require the grid operators to file progress reports on their stakeholder processes.
ELCON said any action should be a common solution across all RTOs to avoid exacerbating seams issues. Xcel Energy — which doesn’t operate in the three Eastern RTOs — said FERC should reiterate that the docket is limited to RTO/ISO markets, urging it to “do no harm” to unbundled states.
EPSA said energy price formation should be a priority, calling for completion of Notices of Proposed Rulemaking on the pricing of fast-start resources (RM17-3) and addressing uplift allocation and transparency (RM17-2). (See FERC Seeks More Transparency, Cost Causation on Uplift.)
The R Street Institute called for FERC to issue a new NOPR setting a “bright line” on state policies that would be subject to the MOPR or legal challenges. “This would offer a more proactive approach than retroactive litigation, deter egregious interventions and perhaps disarm state-federal tensions.”
Public Citizen said the paths outlined by FERC are too narrow to solve the problems and that competitive markets may not always be the best solution. It said the commission should start by conducting an evidentiary hearing on whether RTO markets are resulting in just and reasonable outcomes. It also called for governance changes to allow non-governmental organizations voting rights in the RTO/ISO stakeholder process.
New England’s public power utilities aren’t convinced that ISO-NE’s proposed two-tiered capacity auction is the best way to incorporate state clean energy procurements into the wholesale markets.
At FERC’s May 1-2 technical conference on state policies and wholesale markets, ISO-NE presented its Competitive Auctions with Subsidized Policy Resources (CASPR) proposal, which it said would incorporate state-mandated renewable generation while preventing oversupply and addressing objections to a regional carbon tax. (See ISO-NE Two-Tier Auction Proposal Gets FERC Airing.)
In post-conference comments filed with the commission, several major New England stakeholders indicated they were willing to consider the RTO’s plan.
The Massachusetts Department of Public Utilities said it “generally agrees” with the four objectives of the ISO-NE proposal: “(1) competitive capacity pricing; (2) accommodating the entry of state policy resources into the [Forward Capacity Market] over time; (3) avoiding cost shifts; and (4) a sustainable, market-based approach.”
The New England States Committee on Electricity (NESCOE) said it will provide analysis later this year “on a variety of mechanisms through which states could execute policy objectives,” including Path 4 long-term “achieve” proposals and near-term Path 2 “accommodate” proposals such as CASPR. “NESCOE will continue to work with ISO-NE, market participants and others to explore potential solutions that could improve upon the status quo,” NESCOE told FERC.
However, the RTO’s plan got a wary response from the Eastern New England Consumer-Owned Systems (ENECOS). “The history of New England’s Forward Capacity Market (FCM) has not been a happy one from the perspective of small, vertically integrated utilities,” the group wrote. “To suggest — as some have in the technical conference — that the answer to the ‘threat’ posed by the prospect of large-scale entry of variable-energy, renewable resources into the current centralized auction construct is to create yet another centralized auction construct [invites] extreme skepticism.”
The group said any solution “should be coupled with restoration of the right of self-supply for load-serving entities as a means of satisfying their share of regional capacity obligations.”
ENECOS said both Paths 1 and 3 are “preferable to the more structurally profound proposals — such as carbon ‘adders,’ or creation of yet another centralized capacity auction construct for ‘clean’ energy.”
The Northeast Public Power Association (NEPPA) also had doubts, saying “the capacity market construct is ill-equipped to achieve the policy outcomes FERC, states and consumers desire.”
“When ISO-New England announced the settlement creating the FCM, NEPPA members worked to ensure not-for-profit load-serving entities (LSEs) retained the right to use their own existing resources to meet their capacity obligations,” NEPPA said. “That negotiated benefit was lost when FERC approved the minimum offer price rule (MOPR), which suddenly made the FCM a mandatory construct. ISO-New England is now effectively the single buyer and single seller of wholesale electricity in the region.”
NEPPA also criticized the MOPR as a “flawed construct.” It attached to its comments a concurring opinion by former FERC Chair Norman Bay, a parting shot before his resignation in February in which he called MOPR “unsound in principle and unworkable in practice.” (See Bay Blasts MOPR on Way Out the Door.)
The MOPR would be applied only in the first of the auctions under CASPR. In the first stage, ISO-NE would clear the auction as it does today, applying the MOPR to new capacity offers to prevent price suppression. In the new second “substitution” auction, generators with retirement bids that cleared in the primary auction would transfer their obligations to subsidized new resources that did not clear because of the MOPR. Because the substitution auction will not use the MOPR, it will clear at lower prices than the primary auction, enabling existing resources to buy out their obligations at a lower cost in return for retiring, the RTO says.
CASPR arose out of the New England Power Pool’s Integrating Markets and Public Policy (IMAPP) initiative — a response to state officials’ concerns that consumers could face excessive costs if state renewable procurements were not incorporated into the capacity market and generators’ fears that out-of-market resources will suppress capacity prices. New England states are set to procure more than 3,600 MW of nameplate renewable generation.
Another proposal that arose from IMAPP is the Carbon-Linked Incentive for Policy Resources (CLIPR), proposed by Brookfield Renewable, the Conservation Law Foundation and NextEra Energy.
The “CLIPR Coalition” said long-term Path 4 proposals are preferable to interim Path 2 plans. It asked FERC to issue a policy statement directing the RTOs to submit “achieve” solutions to the commission in the near term and requiring them to file quarterly reports on their progress.
Under the CLIPR proposal, LSEs would pay state “policy” resources an energy price premium that would fluctuate based on the “marginal carbon intensity” of the dispatch, “a direct analog to the LMP but computed as lbs-CO2/MWh instead of $/MWh.”
Urgency
The New England stakeholders also disagreed over how quickly the region must act and how involved FERC should be in the process.
State officials generally downplayed the urgency. NESCOE said “the overall level of state-sponsored clean energy procurements that have taken place or are expected in the near-term comprises a small percentage of installed resources on the system.” It also defended state sovereignty and urged the commission not to take “prescriptive action.”
The Massachusetts DPU noted that the states’ procurement of clean energy resources “will extend over many years.”
“There is no evidence to suggest the current market construct is causing any decrease in merchant investment,” said a joint filing by the Connecticut Department of Energy and Environmental Protection, Public Utilities Regulatory Authority and Office of Consumer Counsel. “On the contrary, New England has attracted a large amount of new investment over the last several years, including renewable generation.”
The New England Power Generators Association (NEPGA) sees it differently. “NEPGA believes that the wave of out-of-market resources beginning to crest in New England threatens the very viability of a competitive wholesale electricity market,” it said. “The need is urgent, with a necessary direct and swift response from FERC and the wholesale markets.”
Efforts to incorporate New York’s aggressive climate change policies into NYISO markets are focused on the introduction of a carbon price adder.
The ISO told FERC it has “engaged in a productive dialogue” with state regulators since the May 1-2 technical conference on state policies and wholesale markets.
NYISO is working with The Brattle Group, stakeholders and regulators to determine the feasibility of “Path 4” market design changes in response to the state’s Clean Energy Standard (CES) and its zero-emission credits for Exelon’s Nine Mile Point, R.E. Ginna and James A. FitzPatrick nuclear plants. The CES mandates reducing greenhouse gas emissions by 40% by 2030, from a 1990 baseline, and by 80% by 2050. It also calls for renewables to meet 50% of the state’s energy needs by 2030. (See Carbon Adder to Test FERC’s Independence, IPPNY Panelists Say.)
Nine Mile Point | Constellation Energy
About 80 parties filed post-conference comments. Among those who expressed support for a Path 4 approach, in addition to the ISO and the Public Service Commission, are New York City, the New York Power Authority and the Independent Power Producers of New York (IPPNY).
The city said Paths 2 and 4 provide the “best opportunities to correct current market constraints” on renewable resources and new technologies procured under public policy goals.
The single-state ISO can “craft a wholesale market structure that wholly integrates the state’s renewable energy objectives and provides renewable generation with better access to the marketplace,” the city said. “Market entry and exit should take into account whether the public good is being served, and whether principles related to resiliency and the improvement of air quality and public health are being advanced or hindered.”
NYPA expressed interest in exploring Paths 1, 2 and 4, and called for the elimination or a scaling back of the minimum offer price rule (MOPR). “The commission should accept state actions which do not interfere with FERC’s responsibilities,” it said.
But a group of about 60 large industrial, commercial and institutional energy consumers in New York who filed as “Multiple Intervenors” said it is not convinced of the wisdom of the Path 4 approach. The group said a status quo Path 3, while “not optimal … may be the most realistic among the choices identified” by FERC.
While the New York Public Service Commission said its work with NYISO to incorporate carbon into the wholesale markets “might be viewed as an endorsement of Path 4,” it said Path 2 “illustrates the limitations of the five paths.”
“While Path 2 may appear to represent a ‘compromise’ position, it hampers the ability of states to carry out legitimate public policies. Further, Path 2’s explicit goal to ‘maintain certain wholesale market prices,’ rather than the original, narrower purpose of mitigating for market power, shows how far afield MOPRs have strayed,” the commission said. “It asserts the right ‘to maintain certain wholesale market prices consistent with the market results that would have been produced had those resources not been state-supported.’ No true market operates in this manner.”
The ISO told FERC it has “engaged in a productive dialogue” with the state Department of Public Service, which includes the PSC, since the May conference and expects to release Brattle’s preliminary findings “in the near future.”
The report can’t come too soon for IPPNY, which said that FERC should require the ISO to file its carbon adder proposal and the Brattle analysis of it as soon as it regains its quorum.
“If the NYISO decides not to file such a proposal, the commission should require the NYISO to explain the basis for its decision,” IPPNY said. “In addition, if the commission decides that capacity markets should be modified to accommodate state public policies, it should direct the NYISO to adopt a forward capacity auction similar to the markets in PJM and ISO-NE.”
Noble Environmental Power, which claims to be the largest wind generator in New York, said its six projects totaling 612 MW will stop receiving state renewable incentives within the next two years. “As more new wind facilities enter the already bottled market in Upstate New York with discriminatory out-of-market incentives to meet state policy goals, energy prices will be substantially reduced — with a significant likelihood that the projects’ output will be curtailed under market dispatch rules.” It called for a Path 4 solution, saying FERC should order the ISO to integrate emissions-free electricity as an attribute in its markets to ensure “a level playing field” for renewables and nuclear generators.
Urgency
IPPNY, Eastern Generation, New York City and the Multiple Intervenors said the need for action is urgent. “Conflicts between state public policies and federally regulated wholesale electricity markets almost certainly will continue to get worse, thereby harming customers and other market participants irreparably,” the large customer group said.
The PSC agreed “the need to address these issues is urgent.”
But it added, “proper time must be given to explore possible solutions. … This is not the time to rush into a quick fix without thought of the impacts on the market and legitimate public policy goals.”
When PJM officials sought to prevent a repeat of the generation outages that nearly forced rolling blackouts in the winter of 2014, they quickly realized no solution was likely to clear a two-thirds sector-weighted vote — required to file proposals under Section 205 of the Federal Power Act.
As a result, the PJM Board of Managers filed its Capacity Performance rules unilaterally under FPA Section 206 after only a limited stakeholder review.
Winning approval of the RTO’s five sectors is difficult enough. Now, as PJM attempts to ensure the zero-emission credits approved for nuclear plants in Illinois — and similar measures under discussion in Ohio, New Jersey and Pennsylvania — don’t suppress prices, the needle may be even tougher to thread.
The RTO’s footprint includes D.C. and parts of 13 states — states with disparate energy and environmental policies, including both restructured and vertically integrated constructs. Maryland and Delaware are members of the Regional Greenhouse Gas Initiative (RGGI), a market-based program to reduce emissions.
In contrast, PJM members and coal producers West Virginia and Kentucky don’t even have renewable portfolio standards. (New Jersey appears likely to rejoin RGGI after Gov. Chris Christie, who pulled his state from the compact in 2011, leaves office in January. Both the Democrat and Republican candidates running to replace Christie have promised to rejoin.)
The differences in stakeholder views were displayed at FERC’s May 1-2 technical conference on state policies and wholesale markets, and they were also evident in post-conference comments filed at the end of June. (See PJM Stakeholders Offer Different Takes on Markets’ Viability.)
The commission asked commenters to weigh in on five potential “paths” of action (see table).
In their remarks, PJM officials told FERC they are pursuing three initiatives:
Allowing states to voluntarily join a system incorporating carbon pricing with existing market structures. This approach, which would require a “critical mass” of states to agree on a “common template,” is in the “beginning stage,” CEO Andy Ott told the commission.
A two-phase capacity auction that would allow subsidized resources to be counted as available reserves without influencing the clearing price.
Changes to energy market rules to improve price formation, which PJM says could reduce the need for out-of-market actions by states. It would expand on the issues identified in FERC’s Notice of Proposed Rulemaking on the pricing of fast-start resources (RM17-3). (See FERC: Let Fast-Start Resources Set Prices.)
PJM said the Path 2 “accommodate” route “is most in need of the earliest feasible commission guidance and ensuing market rule adjustments,” citing concern that price suppression from ZECs and other state generation subsidies could be “exported” from those states to other regions.
Supporters of Path 2 include FirstEnergy and Eastern Kentucky Power Cooperative, which filed jointly, and Public Service Enterprise Group, which is seeking financial support for its Salem and Hope Creek nuclear plants in New Jersey.
PSEG said it will not keep its nuclear plants in service if they are not “economically viable.” Company executives told analysts on an earnings call in April that the units will be cash-flow positive at least through 2019 but that the plants’ finances could worsen by 2020. FirstEnergy, which has been trying for years to win subsidies from Ohio for its merchant fossil fleet, has recently sought aid for its Davis-Besse nuclear plant.
Davis Besse Nuclear Power Plant
PJM’s Independent Market Monitor, which opposed the Illinois ZECs, said “it would be a mistake for ISO/RTOs to explicitly accommodate state-level subsidies” in their capacity market designs.
The Monitor criticized the focus on so-called “baseload” resources. “The concept of baseload resources is backward rather than forward looking. Baseload units are units that run for most hours of the year. But the term baseload is now frequently used to mean units that used to run a lot of hours based on old economics, that no longer run a lot of hours based on current economics, and that are seeking subsidies to make up the difference in revenues.”
It opposed Paths 1-3, calling for a combination of Paths 4 and 5.
Direct Energy also weighed in on the baseload issue.
“The commission must ensure that to the extent there is an alleged need to retain baseload units for fuel diversity — which … may inevitably lead back to integrated resource planning — there is demonstrable and verifiable proof that without this retention, the electric infrastructure is in jeopardy from a security perspective,” it said. “Consumers paid far more than they should have in the days when utilities and regulators chose winners and losers through [the] integrated resource planning period. The commission cannot allow the cost efficiency and choices afforded to consumers through competition to be eviscerated without good reason.”
Andrew Place, vice chairman of the Pennsylvania Public Utility Commission, endorsed Path 4 as the “most prudent approach.” The PUC, however, declined to take a position, citing uncertainty over how legislators in Pennsylvania, Ohio and New Jersey will respond to potential nuclear closures.
The Maryland Public Service Commission also withheld judgment on PJM’s proposed two-stage capacity auction, saying “the scope and scale of the proposal are uncertain.”
In a joint filing, American Electric Power and Dayton Power and Light expressed doubts about the ability to value and integrate state policies into markets. “While a New York carbon policy might be reflected in a carbon adder integrated into the NYISO’s market design, where there is only one state policy to address, such integration would be much more challenging in PJM, where the geographic and political diversity of the covered states would make policy consensus difficult to achieve.”
The companies also said PJM’s proposed two-stage auction could introduce “perverse incentives,” encouraging deregulated units to offer into the first-round auction at zero in order to clear the auction and qualify for the likely higher prices in the second round.
Public power commenters pushed back hard on PJM’s plans.
Old Dominion Electric Cooperative said the PJM proposal is not just and reasonable and called on FERC to avoid the “volatility of reactionary rule changes.”
The American Public Power Association said “PJM’s approach would by its design over-procure capacity resources, further increasing costs to consumers.”
American Municipal Power said FERC should order a five-year transition from the current PJM capacity model to one in which only 20% of capacity is procured through the auction with the remaining 80% procured through bilateral contracts.
Duquesne Light took the opposite position, saying it opposes the expansion of bilateral contracting.
It also said the current 90-day notice for generation retirements should be increased to 210 days. “The current 90-day advance notice of retirement of a unit is inadequate to allow PJM, the market and market participants to study and implement contingency plans to account and properly plan for the loss of generation,” the company said. “Generation deactivations can create local reliability problems whereby the totality of impacts cannot be identified within the current 90-day time frame nor can potential solutions be constructed within that 90-day window.”
The PJM Industrial Customer Coalition said the RTO’s “Capacity Market Repricing Proposal” whitepaper is “worthy of” further discussion but said it is strongly opposed to state mechanisms to price environmental attributes.
AEP and Dayton said FERC should consider the impact of state policies on transmission planning, not just capacity and energy markets.
“State-subsidized renewable generation investments may only be feasible in specific locations that require additional transmission to assure delivery. Market efficiency transmission projects are based on price signals in the energy and capacity markets,” the companies said. “Artificially low price signals, for instance, may cause significant delays in the planning and construction of transmission projects that could provide more cost-effective solutions to addressing generation retirements.”
They also commented favorably on the idea of creating a separate capacity tranche for resources based on their “resilience,” such as on-site fuel supplies, ramping capabilities and ancillary reliability services.
The Monitor agreed: “It is urgent that the identified issues be addressed.
“But it is not so urgent as to prevent a rational, forward looking and collaborative approach to addressing the issues that are faced by all,” it said. It noted that three-quarters of nuclear plants covered 100% of their going-forward costs in 2016.
The PJM ICC said there was “no need for rush to judgment.”
The New Jersey Board of Public Utilities said wholesale markets are limiting the diversity of its energy portfolio because they “may not adequately value all attributes.”
New Jersey, which gets about 45% of its power from nuclear units, will likely see that fall in 2019 — when Exelon’s Oyster Creek plant is slated for retirement — even if PSEG keeps its plants running.
The Chicago-based Environmental Law and Policy Center said it has “yet to see evidence that near-term action is needed.” It called for extending the deadline on the RTO’s Capacity Construct/Public Policy Senior Task Force, which was created in January 2016. Its charter calls for it to complete its work by the end of the year.
“We are concerned about undue discrimination between resources, unreasonable costs imposed on consumers and interference with states’ environmental policies in order to address a ‘problem’ — low prices — that does not appear to actually be a problem,” the group said in a filing it made on behalf of the Natural Resources Defense Council’s Sustainable FERC Project. “These concerns are exacerbated by not allowing sufficient time and stakeholder process to carry out the work of the CCPPSTF or evaluate proposals addressing similar issues put forth outside of the CCPPSTF. There is no urgency to justify rushing the process, particularly where accelerating the process means key questions are going unanswered and result in poorly considered proposals.”
A Montana utility commissioner was caught on a hot microphone last week appearing to confirm what renewable energy advocates say they already suspected: that state regulators knowingly put rules in place that will suppress development of small solar projects by altering the contract terms available to generators under the Public Utility Regulatory Policies Act.
Lake | Montana PSC
During a break in a June 22 meeting of the Montana Public Service Commission, a microphone — inadvertently left on — picked up Commissioner Bob Lake speaking privately about a recent decision to reduce the standard contract length and rate available to qualifying facilities up to 3 MW under PURPA.
Enacted by Congress in 1978 to encourage diversification of energy supplies, PURPA requires utilities to pay QFs the cost a utility would incur for supplying the power itself or by obtaining supplies from another source. The law leaves it to each state’s utility commission to formulate those rates and set contract terms, depending on project size.
QF Death by Attrition
Lake’s comments were captured in a video posted by the Billings Gazette, which shows him and PSC rate analyst Neil Templeton discussing the commission’s move to cut QF rates by about 40% and reduce contract terms from 25 years to five years with the option to negotiate rates for an additional five years. NorthWestern Energy last year complained that QF rates were 35% above its “avoided costs” and asked that they be reduced (Docket No. D2016.5.39).
“It’s essentially a five-year rate, so … it’s going to probably kill QF development entirely,” Templeton said in the footage.
Lake and Templeton discussing QF Contracts
“Well, actually, a 10-year [contract length] might do it if the price doesn’t,” Lake replied. “And honestly at this low price, I can’t imagine anyone going to get into it. So, it becomes a totally moot point because just dropping the rate that much probably took care of the whole thing.”
“We’re live,” Lake worries later in the video. An unidentified staffer in the room assures him that microphones are turned off.
The incident follows FERC’s January decision to decline enforcing PURPA against the PSC. Solar advocacy group Vote Solar had complained that the state regulators violated the law when it allowed NorthWestern to suspend its tariff for solar QFs pending a rate review (EL16-117). (See FERC Won’t Act on Montana Regulators in PURPA Dispute.)
No Surprise for Solar Supporters
Jenny Harbine, an attorney with Earthjustice representing Vote Solar, was unsurprised by the content of the recorded conversation but surprised that the comments were captured.
“It’s remarkable that the concession was caught on tape, but as a general proposition, it’s well understood by the rest of the world,” Harbine told RTO Insider. “You can’t finance an energy project with a five-year contract any more than I can finance my home with a five-year mortgage. Commissioner Lake and the commission staff confirmed on the open mic that they understand that solar development [under the new five-year contract] is not feasible.
“When state commissions set unreasonably short contract lengths, development of those projects fall off a cliff. There’s evidence of that,” Harbine added. “What the commissioner conceded is that he understood a shorter contract length would close the door on those projects.”
Another notable point about the commission’s decision, according to Harbine: While NorthWestern had asked the commission to reduce the amount paid to QFs under PURPA, the utility did not ask for a shorter contract length.
“The commission took that upon themselves,” Harbine said, adding that developers should be “hopping mad.”
PSC’s Defense
PSC Communication Director Chris Puyear said the decision to reduce the QF contract length and rate boils down to price fairness for ratepayers.
“It’s not the role of the commission to pick winners and losers in the energy landscape,” Puyear said in an email. “Federal law says ratepayers shouldn’t have to overpay for electricity produced by independent generators, but that’s exactly what was happening in Montana.”
Customers were “forced to pay nearly double the market price of electricity for power produced by independent solar facilities” under Montana’s previous QF rate, he added.
“The commission’s action brings rates for independent power in line with what customers would otherwise pay for power produced by the utility, while ensuring that long-term, fixed price contracts do not shift undue risk to the ratepayer,” Puyear said.
“In making its determination on avoided cost and contract length, the commission relied heavily on record evidence, especially the testimony of the state ratepayer advocate, the Montana Consumer Counsel.”
The California Supreme Court on Wednesday declined to review a challenge of the state’s greenhouse gas cap-and-trade program, preserving the 2006 law that requires power plants and other polluters to reduce carbon emissions or purchase state-issued credits.
The court declined to review the California Chamber of Commerce’s appeal of an April 6 decision by the Third District Court of Appeal favoring of the program.
NRG’s Etiwanda natural gas plant, Ranch Cucamonga
While the business interests represented by the chamber did not oppose the California Global Warming Solutions Act of 2006, which set the emissions limits, they attacked the associated California Air Resources Board (CARB) regulations that created the cap-and-trade program allowing the sale of some greenhouse gas emissions allowances.
The legislation required covered entities such as power plants to reduce greenhouse gas emissions to 1990 levels by 2020 and designated CARB to monitor and regulate emissions sources.
Under the program, large emitters of greenhouse gases must purchase emissions credits at CARB’s quarterly auctions to cover emissions not accounted for with free credits. The plaintiffs said the auction sales exceeded the State Legislature’s delegation of authority to the board, and that the revenue generated amounts to a tax.
The appeals court in its earlier ruling said “the legislature gave broad discretion to the board to design a distribution system, and a system including the auction of some allowances did not exceed the scope of legislative delegation.” The court said the legislature later ratified the system by specifying how to use the proceeds.
The appeals court also said the revenue is not a tax because it is a voluntary decision driven by business judgments regarding whether it is better to buy credits than reduce emissions, which, unlike a tax, has value.
“Reducing air emissions reduces pollution, and no entity has a right to pollute,” the lower court said.
The chamber did not immediately respond to a request for comment on the high court’s decision.
The Environmental Defense Fund and Natural Resources Defense Council intervened in the proceeding on behalf of CARB.
“This is the final step in this case to affirm California’s innovative climate program, including its carbon auctions, which serves as a vital safeguard to ensure polluters are held accountable for their pollution,” EDF senior attorney Erica Morehouse said in a statement.
Even with the court challenge behind it, cap-and-trade still faces an uncertain future. Gov. Jerry Brown is trying to extend the life of the program, which expires in 2020, through a ballot measure.
The California Supreme Court (photographed above) upheld a lower court ruling
“With this Supreme Court victory, now it’s up to us to take action extending California’s cap-and-trade system on a more permanent basis,” Brown said in a statement.
CARB is expected to auction about half of the program’s total allowances by 2020. As of January 2015, about 500 million allowances had been given away and about 75 million were auctioned.
