Georgia regulators Thursday voted to allow Georgia Power and its partners to complete the two nuclear reactors under construction at the Vogtle Electric Generating Plant near Waynesboro.
The state’s Public Service Commission unanimously approved a motion by Commissioner Tim Echols finding that the reactors, which would be the plant’s third and fourth generating units, should be completed.
The shield building wall of Plant Vogtle’s Unit 3 in November 2017 | Georgia Power
The new units, like the rest of the plant, are jointly owned by Georgia Power, Oglethorpe Power, the Municipal Electric Authority of Georgia and Dalton Utilities. In July, they became the only nuclear generating units still being built in the U.S. when SCANA and Santee Cooper canceled the expansion of the V.C. Summer plant in South Carolina after cost overruns related to both plants forced Westinghouse Electric, the prime contractor, to declare bankruptcy in March.
Chairman, President and CEO Paul Bowers | Georgia Power
In a statement, Georgia Power CEO Paul Bowers praised the commission’s decision, calling it “important for Georgia’s energy future and the United States.”
Echols’ motion was based on the assumption that Congress will extend nuclear production tax credits that would benefit the project. If it does not, the motion says, “the commission may reconsider the decision to go forward.”
The motion also reduces the approved revised capital cost forecast for construction of the units to $7.3 billion from $8.9 billion to reflect the parent guarantee payments that Toshiba, which owns Westinghouse, has made to Vogtle’s co-owners. Georgia Power, a subsidiary of Southern Co., said the payments, which totaled $3.68 billion, will reduce the cost of constructing the new units by $1.7 billion.
The motion does not impose a cost cap on the construction, but it also doesn’t guarantee recovery of all costs. It also reduces the return on equity used to calculate the costs Georgia Power and its partners are allowed to recover if Unit 3 is not operational by June 1, 2021, and on Unit 4 if it isn’t running by June 1, 2022. Georgia Power expects Unit 3 to be operational by November 2021 and Unit 4 by November 2022.
By Michael Kuser, Tom Kleckner, Rory D. Sweeney and Rich Heidorn Jr.
FERC dropped its plan for a one-size-fits-all rule on fast-start pricing Thursday, instead issuing individual orders requiring PJM, SPP and NYISO to change their tariffs.
In December 2016, the commission issued a Notice of Proposed Rulemaking that would have set generic rules to ensure RTOs and ISOs incorporate fast-start resources into energy and ancillary services pricing. (See FERC: Let Fast-Start Resources Set Prices.)
But the commission said Thursday it was withdrawing the NOPR, persuaded by commenters who suggested the changes would be burdensome and that it would be better to allow RTOs to implement pricing practices tailored to their regions and generator types.
“Having considered these comments, we are persuaded to not require a uniform set of fast-start pricing requirements that would apply to all RTOs/ISOs. Instead, we will pursue the goals of the NOPR through Section 206 actions involving NYISO, PJM and SPP focusing on specific concerns with each RTO’s/ISO’s implementation of fast-start pricing consistent with the concerns outlined in the NOPR,” the commission said (RM17-3).
Cane Run Unit 7, a fast-start 640-MW combined cycle plant went into service for Louisville Gas and Electric and Kentucky Utilities in 2015 | LGE/KUje
FERC said it had preliminarily concluded that the three regions did not adequately allow fast-start resources to set LMPs, resulting in prices that were not just and reasonable and that muted investment signals.
The commission spelled out about a half dozen tariff changes each that it seeks from PJM (EL18-34) and SPP (EL18-35), and two from NYISO (EL18-33).
Commissioner Robert Powelson called the orders an “appropriate balance.”
Commissioner Cheryl LaFleur said that NYISO “has been an early leader in fast-start pricing … but we still see the possibility through targeted reform to improve certain aspects of their Tariff.”
She added that the commission was not ignoring CAISO, MISO and ISO-NE “just because we were feeling charitable around the holidays.”
“MISO and ISO-NE have largely already implemented the best practices that are outlined in the” Section 206 orders, she said. “With respect to the California ISO, I at least, was persuaded … that this line of reform would provide limited benefit for them relative to their other priorities that are going on right now.”
The commission called on all three regions to relax fast-start resources’ economic minimum operating limits by up to 100% so that they are considered dispatchable from zero to their economic maximum operating limit for setting LMPs.
It also said the three RTOs must modify their pricing logic: PJM and SPP to allow the commitment costs of fast-start resources (start-up and no-load costs) to be reflected in prices, and NYISO to make changes capturing units’ start-up costs.
It also said PJM and SPP needed to spell out their rules and practices regarding fast-start pricing in their tariffs, and include in their definitions of quick-start resources a requirement that those resources have a minimum run time of one hour or less.
The commission ordered the regions and other interested parties to file initial briefs within 45 days after the notice of the Section 206 proceedings are published in the Federal Register. Reply briefs are due within 30 days after initial briefs.
The commission took issue with the way the three regions relax fast-start resources’ economic minimum operating limits to allow them to set prices, as detailed below.
PJM Order
FERC said PJM has special pricing rules only for block-loaded units — resources whose economic minimum operating limits equal their economic maximums, meaning they have no dispatchable range. The RTO seeks to let them set price by relaxing the economic minimum operating limit of online block-loaded resources by up to 10%.
The commission said PJM’s practices may not be just and reasonable because they don’t allow block-loaded resources’ economic minimum to be relaxed by more than 10% and because they limit the relaxation to only block-loaded resources.
Jenbacher2 Reciprocating Engine | GE Power Generation
“We remain concerned that without allowing relaxation by up to 100%, prices will sometimes be set by the offers from lower-cost flexible units that are dispatched down in order to accommodate the output of fast-start resources,” FERC said. “As a result, PJM’s practices may not reflect the marginal cost of serving load when a fast-start resource is needed to quickly respond to unforeseen system needs, which may result in inaccurate price signals.”
The commission also found fault with PJM’s dispatch practices.
“An efficient dispatch can only be reliably determined by modeling the actual system costs and actual system constraints within a market run that minimizes production costs. That is, fast-start pricing logic would ideally not change the dispatch of resources away from the cost-minimizing dispatch but would only alter the manner by which prices are established. PJM does not appear to develop real-time dispatch instructions in this way.”
Because PJM’s practice does not respect the “power balance constraint,” FERC said, the RTO “unnecessarily increases the cost of serving load and puts stress on the frequency regulation resources that are necessary for maintaining system reliability.”
In addition, it said PJM should:
Include in its definition of fast-start resources a requirement that those resources be able to start up within one hour or less (including notification time);
Apply the relaxation of a resource’s economic minimum operating limit to all fast-start resources, not just block-loaded units; and
Dispatch fast-start resources “consistent with minimizing production costs, subject to appropriate operational and reliability constraints.”
PJM stakeholders briefly discussed the order at Thursday’s Markets and Reliability Committee meeting. When members considered a proposal from the RTO to evaluate its energy market price formation procedures, American Electric Power’s Brock Ondayko asked if the fast-start order would be part of that evaluation.
Adam Keech, PJM’s executive director of market operations, noted the order’s short window for reply comments and said, “Certainly from our perspective, we would prefer discussion [on that issue] earlier [rather] than later.”
He said he had not been able to digest the order and had “no idea” if any of the procedures agreed upon for the evaluation are “at odds” with it.
Keech urged stakeholders to endorse the evaluation “to get the discussion started.” The proposal received significant revisions but was eventually endorsed.
SPP Order
The commission found SPP’s approach to pricing quick-start resources to be “inconsistent with minimizing production costs.”
FERC said SPP’s real-time balancing market practices for quick-start resources begins with a “screening run” that identifies a set of resources to be excluded from the binding solution. The screening run identifies an economic dispatch solution under the assumption that quick-start resources may be dispatched below their economic minimum operating limit, the commission said.
Any resources that are dispatched below their economic minimum operating limit are treated as “off” and excluded from consideration in the binding pricing and scheduling run. “This means quick-start resources are only considered for dispatch in the pricing and scheduling run if they are dispatched to at least their economic minimum operating limit in the screening run,” FERC said.
A second optimization pass (pricing and scheduling run) is used to determine both the binding resource dispatch levels and energy and operating reserve prices.
The commission noted two other rules that distinguish SPP’s treatment of quick-start resources from other RTOs’ fast-start pricing practices:
It provides an option for quick-start resources to submit an enhanced energy offer that includes commitment costs (start-up and no-load costs) as part of the incremental cost curve to be used both in the screening run and in the real-time balancing market’s pricing and scheduling run.
SPP does not have any minimum run time requirement for eligibility as a quick-start resource.
The commissioners said SPP’s practices are not in its Tariff, pointing to the Federal Power Act’s requirement that all practices significantly affecting rates, terms and conditions of service be on file with FERC and included in a commission-accepted Tariff.
“For example, the Tariff does not describe the process by which quick-start resources are screened out within the screening run from participating in dispatch, which appears to have a material effect on electric power rates,” the commission said. “Therefore, our preliminary review indicates that SPP’s practices related to quick-start pricing significantly affect the rates, terms and conditions of service and as such, must be filed with the commission as part of the SPP Tariff.”
The commission said SPP should:
Commit and dispatch quick-start resources in real time consistent with minimizing production costs, subject to operational and reliability constraints;
Remove the option for enhanced energy offers for quick-start resources that incorporate commitment costs in the incremental energy curve; and
Consider both registered and unregistered quick-start resources in quick-start pricing to ensure prices reflect the cost of the marginal resource.
NYISO Order
NYISO currently applies fast-start pricing logic to online and offline fixed block units that can start in 10 minutes. The ISO defines a fixed block unit as one that, “due to operational characteristics, can only be dispatched in one of two states: either turned completely off, or turned on and run at a fixed capacity level.”
The commission noted that in the first pass of the optimization process, NYISO establishes a resource’s physical base points (i.e., real-time energy schedules). In the second pass, also called the pricing run, the ISO relaxes the economic minimum operating limit of fixed block units in order to allow them to be eligible to set prices. When pricing offline fixed block units, the price can also include a unit’s start-up costs.
“However, NYISO neither relaxes the economic minimum operating limits of dispatchable resources (i.e., resources that are not block-loaded), nor does it include the start-up costs of these or any online resources for the purpose of setting prices,” the commission said.
FERC preliminarily found that NYISO’s practice of “differentiating between dispatchable fast-start resources and fixed block units appears to be arbitrary and may result in prices that do not reflect the marginal cost of serving load. NYISO’s practice of allowing only fixed block units to participate in fast-start pricing may also create incentives favoring development of block-loaded resources over dispatchable resources. Furthermore, the practice may create incentives for dispatchable resources to withhold their flexibility from the market.”
While finding that such practices may be unjust and unreasonable, the commission noted that there are methods to address concerns about the “potential consequences of relaxing the economic minimum operating limit of fast-start resources” by up to 100%.
WASHINGTON — FERC Chairman Kevin McIntyre closed out his first open meeting Thursday by announcing that the commission would re-examine its 1999 policy statement on certifying new interstate natural gas pipeline facilities.
McIntyre said the effort is in its very early stages and that the scope and format of the review are still being considered.
“Obviously, [since] 1999 … much has changed in the industry,” McIntyre said. “So, without prejudging anything, and without intending to forecast a policy direction … we believe it’s a matter of good governance to take a fresh look at this area, and to give all stakeholders and the public an opportunity to weigh in.”
The policy statement details how the commission grants developers of proposed pipelines a certificate of public convenience and necessity — allowing them to exercise eminent domain — under the Natural Gas Act of 1938. It came at a time when the gas industry, much like the electricity industry, was being restructured, and demand in the northeastern U.S. was expected to increase — somewhat of an understatement in hindsight.
“At a time when the commission is urged to authorize new pipeline capacity to meet an anticipated increase in the demand for natural gas, the commission is also urged to act with caution to avoid unnecessary rights of way and the potential for overbuilding with the consequent effects on existing pipelines and their captive customers,” the statement concludes. “This policy statement is intended to provide more certainty as to how the commission will analyze certificate applications to balance these concerns.”
Since the statement was issued, FERC has granted a certificate to virtually every proposed pipeline submitted to it; Commissioner Richard Glick noted that the amount of new pipeline capacity approved by the commission has grown by more than 500% in the past six years alone.
This has raised the ire of environmentalists and landowners, who charge that FERC “rubber-stamps” pipelines and point to the number of former staffers who have gone on to work in the natural gas industry. Protesters interrupting commission meetings have become a regular occurrence over the past two years. (There were, ironically, no interruptions at Thursday’s meeting.) Members of Congress have also written FERC on behalf of constituents to complain about inadequate public notice for commission hearings on pipelines in their jurisdictions, or a lack of time to accommodate all who wanted to speak.
But there is also a growing concern in the energy industry about the potential for overbuilding pipeline infrastructure as renewable, distributed and storage resources are becoming increasingly relied upon for electricity generation. Just before his resignation in February, former Chair Norman Bay called on the commission to analyze its reliance on signed agreements with shippers to determine the need for pipelines. (See Bay Calls for Review of Marcellus, Utica Shale Development.)
“Overbuilding may subject ratepayers to increased costs of shipping gas on legacy systems,” Bay said. “If a new pipeline takes customers from a legacy system, the remaining captive customers on the system may pay higher rates.”
McIntyre said he did not share any of those concerns, instead citing the policy’s statement age as a factor for his decision to examine it. “The fact of my having proposed this should not be read as … a complaint about our current policy. It is not,” he told reporters after the meeting. “1999 was quite a while ago, particularly in the natural gas pipeline industry. So much has changed” across all energy industries, “but it would be hard to point to an area that has changed more than natural gas.”
His fellow commissioners — it was the first time FERC has had five commissioners in two years — all expressed support for the review.
Commissioner Cheryl LaFleur said she would like the review to focus on how FERC determines economic needs for proposed pipelines, as well as the environmental impacts.
“The policy statement … actually holds up quite well. It outlines a very broad range of factors we could look at to review need. Over time our practice has coalesced around a reliance on precedent agreements as a determiner of market need. And as I recently stated in dissents in Atlantic Coast (CP15-554, et al.) and Mountain Valley (CP16-10, et al.) pipelines, I think our review of pipeline applications would benefit from a broader consideration of need,” she said.
“Secondly, I think it’s appropriate for us to consider how we do our environmental reviews … [to consider] the downstream impacts on greenhouse gases or other downstream impacts,” she continued. “I was already looking forward to 2018 with all you fine folks, and I now am even more.”
In August, the D.C. Circuit Court of Appeals ruled that FERC’s environmental impact statement (EIS) for the Southeast Market Pipelines Project should have included “reasonable forecasting” of the project’s impact on GHG emissions.
As interim chairman, Commissioner Neil Chatterjee said in October that he didn’t expect the ruling to have a “significant” impact on the agency’s pipeline licensing. (See FERC Chair: Court Ruling Won’t Change Pipeline Reviews.)
“Although I am supportive of our current policies, I wholeheartedly agree with the chairman that it’s important the commission takes a look at how it exercises its statutory obligations,” Chatterjee said Thursday. He emphasized that he wanted input from all stakeholders. “I particularly want to speak to those who feel frustrated that their voices are not heard throughout this process. I want you to know that I empathize with that frustration.”
Commissioner Robert Powelson agreed with Chatterjee’s sentiments, but he also defended FERC’s record. “We don’t rubber-stamp interstate pipelines here,” he said. “People should have peace of mind that, one, we don’t site pipelines on speculation here at the FERC. There is due diligence. … This is about giving everybody an opportunity to be heard.”
“It’s not just that we’re approving a lot of pipeline capacity; that may be OK,” Glick said. “It’s that these pipelines are increasingly traversing populated areas, and thus have potentially greater impacts on individuals and communities, in addition to their impacts on the environment.”
McIntyre told reporters that any outcome of the review would affect the pipelines currently before the commission.
“I am approaching this topic with an open mind and want the staff and the commission to take a fresh look at all aspects of the issue,” he said.
MISO has released a draft guide detailing how it estimates costs for cost-allocated transmission projects after state officials and stakeholders called for more transparency around the process.
The guide is intended to cover any market efficiency or multi-value projects that might be approved under MISO’s 2018 Transmission Expansion Plan. State regulators in the Organization of MISO States earlier this year asked the RTO to provide more visibility on project costs. (See Commissioners Ask MISO to Share Tx Project Cost Data.)
The RTO is asking stakeholders to review the guide and suggest revisions by the end of January. After being vetted by stakeholders, the guide will become effective in March, MISO design engineer Alex Monn said during a Dec. 18 Planning Subcommittee conference call.
MISO accepts stakeholder assessments as a starting point for estimating the costs for market efficiency and multi-value projects but develops final planning-level cost projections based on its own project assumptions.
The RTO said its total estimates include a construction cost estimate, a 20% construction cost contingency fund and a 7.5% allowance for funds used during construction. MISO initially uses a straight line plus 30% calculation to estimate transmission line length, then updates the measurement using the proxy route provided by transmission developers. For substation upgrades and new builds, it similarly uses general estimates based on the area, then updates cost needs once developers submit more details.
For the construction estimate, MISO factors in land and right-of-way costs in addition to the costs of potential substations, transmission structures, conductor, accessories like shield wire and professional services such as the engineering and testing needed to assemble the line. Right-of-way acquisition terrain and grading estimates are based on the length of the new transmission line and the topography along the route. MISO also said it has the right to assume other project-specific mitigation costs “when necessary.”
Before MTEP 15, MISO relied on transmission owners to provide cost estimates for projects that fell within their service territory, but it began developing its own cost estimates after FERC issued Order 1000. The estimates are used to assess the worthiness of a project: MISO’s Tariff requires a benefit-to-cost ratio of at least 1:1 for multi-value projects and 1.25:1 for market efficiency projects.
2018 Construction Assumptions
The guidelines stipulate that MISO will assume the need for seven tangent structures per mile on 69-kV single circuit line (nine per mile for a double circuit) to three tangent structures per mile on a 500-kV single circuit line (five per mile for a double circuit). For all line ratings, MISO assumes developers use a steel pole structure type, except for 500-kV lines, which will have steel lattice towers.
The RTO also assumes a right-of-way width of anywhere from 80 feet for 69-kV and 115-kV lines, and up to 200 feet for 500-kV lines. For substations, MISO will assume 1.5 acres are needed for a 69-kV rated substation, 1.75 acres for a 115-kV substation, 2 acres for a 138-kV substation, 2.5 acres for a 161-kV substation, 4 acres for a 230-kV substation, 8 acres for a 345-kV substation and 20 acres for a 500-kV substation. Land costs for the 2018 planning year will vary by state, with the cheapest land in Montana for $677/acre and the most expensive in Illinois at $3,583/acre.
To mobilize and then break camp for all equipment and people needed for construction of a project, MISO will assume costs ranging from $51,250 for a 69-kV project to $153,750 for a 500-kV line project, up to $262,660 for certain substation work.
For terrain-clearing costs, MISO will assume $260/acre for level ground with light vegetation, $4,920/acre for forested land and $57,500/acre for wetland matting, as well as an additional $46,125/acre to secure environmental mitigation credits for wetlands. MISO will also factor in a $6,400/acre cost to grade any mountainous terrain a transmission line might traverse.
As part of the guide, MISO is also releasing state-by-state exploratory construction estimates, which represent high-level cost estimates for potential projects that still lack specifics.
The exploratory cost estimates range anywhere from $1.2 million/mile for a single-circuit 69-kV line in Iowa, the Dakotas and Montana, to $6 million/mile for a double-circuit 500-kV line in Arkansas, Louisiana and Mississippi.
A MISO task team is slated for retirement after successfully developing several changes to the RTO’s competitive transmission process that were approved by FERC.
The Planning Advisory Committee on Tuesday passed a motion recommending that the Steering Committee approve the immediate retirement of the Competitive Transmission Task Team. Six sectors voted in favor with three abstaining.
Brian Pedersen, MISO senior manager of competitive transmission administration, said the task team has completed its work to improve the selection process behind competitive transmission projects. The team was created last December days after the conclusion of the RTO’s first competitive process, for the Duff-Coleman 345-kV transmission project in southern Indiana and western Kentucky. (See LS Power Unit Wins MISO’s First Competitive Project.)
“In 2017, we sought out incremental operational changes to scale our competitive transmission process. From our perspective, this has been a successful process,” Pedersen said during a Dec. 19 PAC conference call.
Consequently, MISO submitted five FERC filings to amend the competitive process portions of its Tariff — all of which were accepted without changes by the commission. (See FERC OKs Changes to MISO Competitive Tx Process.)
The changes allow the RTO to:
Review and weight competitive projects that contain both substation and transmission line facilities (ER18-44);
Stagger its current proposal submission and evaluation timelines should the RTO encounter two simultaneous competitive projects (ER18-41);
Replace the annual qualified competitive transmission developer recertification process with a biennial process (ER18-40); and
Request a description of safety measures transmission developers will take during both construction and operations and maintenance (ER18-42).
A fifth filing was made to correct grammar, citation and formatting errors (ER18-39).
MISO updated its Business Practices Manuals and request for proposal forms to align with the changes, Pedersen said. He added that MISO will still take up any future stakeholder improvement suggestions “as conditions permit.”
Pedersen said the changes will be in effect for MISO’s second-ever competitive project, the $130 million Hartburg-Sabine 500-kV line market efficiency project in eastern Texas, which will be bid out in early 2018. MISO has hired two new employees to help with the evaluation and selection process for the project, which includes substation construction — a first for its competitive projects.
The project — originally intended to be approved with MISO’s 2017 Transmission Expansion Plan — is currently subject to an approval delay while the RTO awaits a FERC decision on separating cost allocation zones in Texas and Louisiana. (See MISO Board Approves $2.6B Transmission Spending Package.) The Board of Directors has pledged to approve the project no later than Feb. 5, and the RTO plans to issue its RFP on Feb. 6. The window for proposals will be open until July 20, with MISO expecting to announce a developer no later than Jan. 2, 2019.
Pedersen said the Hartburg-Sabine project will be evaluated similarly to last year’s evaluation of the Duff-Coleman project, with cost and design details weighted at 30%, project implementation at 35%, operations and maintenance at 30%, and transmission planning participation at 5%.
Forty-seven existing qualified developers will not be required to recertify next year after FERC accepted MISO’s biennial qualification process, although Pedersen said developers must still disclose annual audited financial statements along with statements of any material changes to keep the RTO aware of developments such as bankruptcies or business name changes.
Queue Task Force Extension
PAC sectors also voted overwhelmingly to extend the RTO’s Interconnection Process Task Force through December 2018. The group will oversee and suggest further improvements to MISO’s major queue process changes made at the beginning of this year. (See FERC Accepts MISO’s 2nd Try on Queue Reform.)
BOSTON — Three developers submitted proposals Wednesday in response to Massachusetts’ solicitation for up to 800 MW of offshore wind energy, offering projects that include a transmission “backbone” and storage to enable them to perform like a baseload resource.
The state’s 2016 Act to Promote Energy Diversity mandates that the Department of Energy Resources and the state’s distribution utilities — Eversource Energy, National Grid and Unitil — sign long-term contracts for 1,600 MW of offshore wind by June 30, 2027. (See Massachusetts Bill Boosts Offshore Wind, Canadian Hydro.)
| BithEnergy
The state’s first request for proposals (solicitation 83C) called for a minimum of 400 MW but said the state would consider bids of up to 800 MW if it determines that a larger proposal “is both superior to other proposals submitted in response to this RFP and is likely to produce significantly more economic net benefits to ratepayers.”
The three developers — all with ties to the state’s utilities — have purchased renewable energy leases off the coast from the federal Bureau of Ocean Energy Management.
Bay State Wind
Bay State Wind, a joint venture between Ørsted and Eversource, proposed a 400-MW or 800-MW wind farm 25 miles off of New Bedford. It would be paired with a 55-MW battery storage facility, “the largest battery storage system ever deployed in conjunction with a wind farm,” it said.
Ørsted, formerly DONG Energy, is the No. 1 offshore wind generator in the world. The company would use New Bedford as the staging area for construction and the base of its operations and maintenance through the wind farm’s lifetime. The storage facility and an onshore substation would be located in Somerset.
Deepwater Wind
Deepwater Wind’s proposal would firm its project’s wind output through an agreement with the largest hydroelectric pumped storage facility in New England, the 1,200-MW Northfield Mountain station operated by FirstLight Power Resources.
Interior of Northfield Mountain pumped storage facility | Northfield Mountain
Deepwater proposed two versions of Revolution Wind, a wind farm of approximately 25 turbines to generate 200 MW, or double that size to generate 400 MW. The company had proposed an initial 144-MW phase of the project in response to the state’s 83D solicitation for 9.45 million MWh of clean energy. The state is due to announce winners of that RFP on Jan. 25.
Deepwater is the developer of the Block Island Wind Farm off Rhode Island, the nation’s first commercial offshore wind farm. It also partnered with National Grid Ventures to propose an offshore transmission “backbone” scalable to 1,600 MW that would be open to other wind developers. (See Offshore Wind Developers Ponder Tx Options.)
The company’s project would connect to land at the Brayton Point substation in Somerset.
Vineyard Wind
Vineyard Wind, a joint venture of Avangrid Renewables and Copenhagen Infrastructure Partners, is betting that its promise to deliver an operating project by 2019 will win the state’s favor. It submitted proposals for 400-MW and 800-MW wind farms, with approximately 50 and 100 turbines, respectively. Avangrid owns Unitil.
| BOEM
Vineyard Wind said it has already submitted applications with BOEM and the state Department of Public Utilities’ Energy Facilities Siting Board for the wind farm, about 15 miles south of Martha’s Vineyard. “By filing for construction permits, Vineyard Wind is on track to complete the permitting process in time to begin construction in 2019,” it said.
Deepwater said if it is selected it would begin construction in 2022, with the project in operation in 2023. Bay State did not mention a timeline in its press release.
The state will announce the winners of the offshore wind solicitation on April 23, 2018, and contracts are to be submitted at the end of July.
This month saw an early offshore wind project, Cape Wind, exit the stage. It announced Dec. 1 that it had notified BOEM it was stopping development of its proposed wind farm project in the Nantucket Sound and filing to terminate its offshore lease issued in 2010.
Nevertheless, the state’s solicitation has been a cause for optimism among green energy advocates, who note the attractiveness of the Atlantic’s strong winds and shallow waters. (See ‘Momentum’ Seen for U.S. Offshore Wind.)
Entergy on Monday asked FERC to clarify the deadline for NYISO to complete a final market power review for the deactivation of the Indian Point nuclear plant, or grant the company’s request to rehear the commission’s approval of a previous ISO compliance filing (ER16-120, EL15-37).
| Entergy
At issue is FERC’s November conditional acceptance of NYISO tariff revisions to implement a new reliability-must-run program. (See FERC Approves NYISO Reliability-Must-Run Plan.) The ISO in September submitted a compliance filing to implement revisions to its RMR proposal, including adding a 365-day notice period for a generator to tell the ISO it plans to retire. The commission had accepted an earlier compliance filing for the proposal, but in April 2016 directed NYISO to make further changes to the program.
In its Dec. 18 filing with FERC, Entergy said that while NYISO’s second compliance filing contained a 90-day deadline for completing reliability studies related to plant shutdowns, it did not contain a provision for a 120-day market power review deadline included in the first compliance filing. As a result, the commission’s Nov. 16 order was “arbitrary, capricious, unsupported by substantial evidence and not a result of reasoned decision-making” because FERC conditionally accepted the ISO’s compliance filings without requiring it to establish a clear deadline early in the process for deactivating generators, the company argued.
Entergy contended that without a clear deadline for review, the 2,311-MW Indian Point plant lacked certainty about its authorization to exit the market in accordance with NYISO’s tariffs.
“At the very least, the NYISO should be held to its own assertions,” Entergy said. “Here, the NYISO has emphasized the need to perform any necessary market power review at the start of this process and has expressly confirmed its ability to complete this analysis in the first four months after receiving a completed generator deactivation notice … [and] a final market power review both in presentations to stakeholders and pleadings before this commission.”
The company is seeking a March 13, 2018, deadline for NYISO to complete a market power study for the closure of the Indian Point.
Artist’s rendering of the Cricket Valley 1020 MW plant | Cricket Valley Energy
An ISO report earlier this month found that new gas-fired and dual-fuel generation coming online in the next few years, led by the 1,020-MW Cricket Valley plant in Zone G, will provide sufficient capacity to maintain reliability after Indian Point shuts down completely in 2021. (See New Builds to Cover Indian Point Closure, NYISO Finds.)
TRENTON, N.J. — If opponents of nuclear subsidies in New Jersey had an opportunity to sway the opinions of state legislators on the issue, it didn’t last long.
During a joint meeting Wednesday of the state Senate Environment and Energy Committee and Assembly Telecommunications and Utilities Committee, members early on indicated their support for a bill that would provide hundreds of millions of dollars in financial support to state nuclear plants. (See Nuke Bailout Bill Introduced in NJ Senate.)
After five hours of testimony, their opinions had not changed. Both committees unanimously voted to move the bill to their respective legislative bodies. ClearView Energy Partners, an energy research firm, said in a statement that the legislature could vote on the bill before the end of next week. It predicted Gov. Chris Christie would sign the bill into law before he leaves office on Jan. 16.
“There’s this constant question about ‘why now?’ The answer is: It’s one of the greenest bills we’ve run into in a long time, and No. 2, we can get it done,” said Sen. Bob Smith, who chairs the Environment and Energy Committee.
Opponents argued that the bill required no commitments from Public Service Enterprise Group, such as a plan for a transition to renewable energy when the plants are eventually decommissioned or a mechanism for the company to pay back any money if market conditions change to make its nuclear plants profitable again.
“You’re feeding the problem that this country faces right now with Donald Trump. We are losing faith in government, and if you [approve] this bill during lame duck, you are part of the problem,” said Doug O’Malley, director of Environment New Jersey. “So hold the bill. Let’s do this right in January, February and March.”
PSEG CEO Ralph Izzo opened the hearing by assuring legislators that enacting the bill was a vote of confidence for his company to commit years ahead of time to investing as much as $200 million annually for the plants’ supply chains.
“There’s been a lot of discussion about this being an automatic handout to utilities. That is not true,” Izzo said, noting that it will be at least 300 days until PSEG will know if its plants qualify for the subsidies proposed under the bill. “Over that time, we will have to decide whether or not to invest between $100 [million] and $200 million in those plants and make an estimate as to whether or not those plants will continue to operate for the remaining 20 or 30 years of their life to make that money back.”
PSEG currently has $275 million in commitments for fuel-related expenses until 2025, he said, and must decide over the next year whether it will commit to keeping the plants open through 2021.
“This is not a rush. This has been an eight-year discussion,” Izzo said. “I encourage you to recognize that driving the vehicle by exclusively focusing on the rear-view mirror is not the safest way to proceed. Most companies look forward on the prospects of their assets.”
Izzo’s comments were rebutted by Stefanie Brand, director of the New Jersey Division of Rate Counsel, who argued that the bill is unclear on how much money PSEG should make or how unprofitable the plants will be without support. Izzo said they will remain profitable at least until next year when a number of PSEG’s energy contract hedges expire.
“There are offramps for the company. There are no offramps for the ratepayers,” she said. ““I’m not advocating for [the plants] to close. I’m advocating for a system that doesn’t allow a single company to hold us hostage in this way.”
Senate President Stephen Sweeney grilled Brand on her concerns, asking whether she thought the state Board of Public Utilities, which would oversee distribution of the plan’s nuclear diversity certificates (NDCs), is capable of fulfilling that role. Brand said it was impossible to know because eligible plants could submit information confidentially without public review. She noted that the subsidized plants would also likely be subject to PJM’s minimum offer price rule (MOPR).
“The rest of us don’t have the information that PSEG does to claim they’ll close. … The consumer protections in this bill are really a delusion,” Brand said. PSEG is “deregulated, so there is no set cost of capital that they are set to earn.”
She added that out-of-state plants, such as Exelon’s Three Mile Island plant in Pennsylvania, might be eligible for the subsidy the way the bill is currently written.
Industry analysts also traded opposing studies on the issue. Dean Murphy with The Brattle Group outlined a study sponsored by PSEG and Exelon that argues it would be cheaper to pay to keep the plants running than to develop replacement power. Tanya Bodell with Energyzt said that report is “flawed” and includes substantial “uncertainty.” She challenged Izzo’s assertion that they might close within two years if they become uneconomic.
“The plants are committed to operate through 2021,” she said. “It would be more costly to retire before 2021.”
Joe Dominguez, Exelon’s executive vice president of governmental and regulatory affairs and public policy, said that while his company can’t decide whether to close the nuclear plants, it can stop investing in them. Exelon can nix any investment over $5 million into the plants, he said, and has come to an agreement with PSEG to begin deferring capital projects “in anticipation of the closure of” the Salem facility.
“As we looked at the market forwards … our concern was that we could no longer invest in the machine given what we were looking at in terms of future energy prices,” he said. “We are already acting on the belief that if adequate attribute payments aren’t provided for nuclear energy in New Jersey, we’re going to take the unit out of service, or at least from Exelon’s perspective, stop investing in the machines.”
One significant opponent to the bill received short shrift from legislators.
After calling NRG Energy CEO Mauricio Gutierrez to testify, Smith referred to him as “Maurice” and declined to attempt his surname, asking him to instead introduce himself. Gutierrez argued that the bill “creates only one winner and many losers, including my company.”
NRG owns no nuclear assets in New Jersey and has a portfolio of mostly gas-fired units. Substantial supplies of natural gas have kept commodity prices low and helped gas-fired generation offer into PJM’s markets at prices below nuclear units. The shift in generation economics has prevented some nuclear units from clearing auctions and denied them payments they say they need to remain profitable.
Gutierrez told the committees that had the subsidies existed before he decided to base his company in Princeton, N.J., he would have placed the headquarters elsewhere. The legislators asked no questions about his testimony, and Gutierrez appeared visibly frustrated as he returned to the audience.
NERC is offering SPP’s 128 registered entities a chance to comment after assigning them all to a new Regional Entity.
The reassignments became necessary when the SPP RE announced its dissolution in July, addressing NERC and FERC concerns over its reliability oversight role. (See SPP to Dissolve Regional Entity.) Responses are due back to the organization by Jan. 5.
NERC said it received 122 transfer requests spanning five REs, with six entities expressing no preference for a “transferee” RE. The organization placed most of the registered entities into the Midwest Reliability Organization (MRO), with 13 Arkansas, Louisiana, Mississippi and Missouri entities assigned to SERC Reliability.
Arkansas Electric Cooperative Corp., which provides power to Arkansas’ 17 distribution cooperatives, was placed in both MRO and SERC.
In a message to the registered entities, RE President Ron Ciesiel said it was the RE’s “understanding” that NERC is on target to present final transferee recommendations to the organization’s Board of Trustees at its February meeting.
“We believe there is a high probability the transfer can be completed in the July time frame,” Ciesiel said.
After an initial review and analysis of entity requests, NERC said it determined that granting all the requests “would neither result in effective and efficient administration of compliance and enforcement activities, nor a cohesive functional alignment to support and promote BPS [bulk power system] reliability and security.”
In reviewing the requests, NERC considered the location of an entity’s BPS facilities in relation to the geographic and electrical boundaries of the transferee RE. The agency also assessed the impact of a proposed transfer on other BPS owners, operators and users, including affected reliability coordinators, balancing authorities and transmission operators, as appropriate.
NERC said it recognized that its procedural rules do not contain criteria for “the allocation of multiple registered entity transfers” when an RE dissolves, so it used criteria from another rule for considering requests. The organization reviewed each transfer request using that criteria and other “entity-specific circumstances.”
When NERC’s recommendations differed from the entities’ requests, it contacted the entities and explained its rationale, the agency said.
Created in 2007, the SPP RE is responsible for auditing and enforcing NERC reliability rules in three balancing authorities: SPP, the Southwestern Power Administration and parts of MISO.
SPP said it is dissolving the RE in part because the RTO’s expanded footprint no longer aligns with the RE’s territory. However, FERC criticized SPP in a 2008 audit for failing to ensure the RE’s independence from the RTO.
Calling 2017 a “tumultuous year for SPP RE,” Ciesiel told its registered entities that RE staff, while working at reduced levels, achieved its highest ever metrics performance.
“A good way to close out the year for us,” he said.
The dissolution is expected to be completed by the end of next year.
ERCOT’s reserve margins may be tightening, but executives on Monday assured reporters that all is well with the Texas grid.
The ISO’s year-end Capacity, Demand and Reserves (CDR) report projects a 9.3% planning reserve margin for 2018, half of what it was in the May report and 4 points below the 13.75% target ERCOT established for itself in 2010. But during a conference call with media, staff described the CDR report’s reserve margin projections as a “snapshot in time” and detailed a list of tools available to handle any emergencies.
“The reserve margin that comes out of the CDR is a snapshot,” said Warren Lasher, senior director of system planning. “Reserve margins are expected to fluctuate in the current market design.”
The May CDR reported an 18.9% reserve margin for next summer. Since then, Vistra Energy has said it would retire about 4 GW of coal resources and ERCOT has reported a year’s delay in completing construction of almost 4 GW of planned capacity. (See Vistra Energy to Close 2 More Coal Plants.)
| ERCOT
Lasher pointed out that since 2010, the Public Utility Commission of Texas has directed ERCOT to develop a new standard for determining the planning reserve margin, similar to a 2014 Brattle Group study on estimating “economically optimal” margins that minimize total system and operating costs. The ISO is currently conducting its own study, which it intends to complete in the third quarter of 2018 before reporting back to the PUC, Lasher said.
| ERCOT
“I wouldn’t call [the CDR] cause for concern,” he said.
ERCOT expects 14 GW of resources to be in service by 2020 and will still have 77.2 GW of capacity on hand to meet a 2018 summer peak demand forecast of almost 73 GW. That would break the August 2016 record peak of 71.1 GW.
Demand is expected to grow at a 1.7% average annually over the next 10 years. The reserve margin is expected to increase to 11.7% by summer 2019, peaking at 11.8% in 2020 before dropping to 9% in 2022. Total capacity is expected to reach almost 83 GW in 2022.
“We see these types of shifts as the ERCOT market experiences cycles of new investments, retirement of aging resources and growing demand for power,” CEO Bill Magness said in a statement.
If the worst comes to worst, Lasher said ERCOT can always request emergency assistance across DC ties with Mexico or the Eastern Interconnection, or fall back on interruptible customers and switchable units obligated to other regions.
The December CDR report includes information about existing and planned generation resources and expected energy needs over the next 10 years. The report does not include the potential additional migration of nearly 600 MW of load should Lubbock Power & Light and Rayburn Country Electric Cooperative eventually migrate customers from SPP into the Texas grid. (See “ERCOT, SPP to Coordinate Second Load-Migration Study,” PUCT Briefs: Aug. 17, 2017.)
