FERC last week accepted several small revisions to MISO’s new interconnection queue design but also told the RTO it must keep working to ensure it sticks to a commitment to reduce restudies.
The commission provided MISO a month to revise its Tariff to eliminate a practice of automatically conducting a restudy based on predetermined triggers, which include a project’s termination or the withdrawal of a project from the queue (ER17-156-002).
| MISO
“In the October 2016 queue reform filing, MISO proposed that, instead of conducting a restudy automatically upon each occurrence of a restudy trigger, the RTO would re-evaluate the need for any common use or shared network upgrades associated with the project,” FERC said.
As of Nov. 2017 | MISO
FERC largely accepted MISO’s new, three-stage interconnection queue in January 2017, but it sought more detail on a few aspects of the plan, prompting a follow-up filing. (See FERC Accepts MISO’s 2nd Try on Queue Reform.) The commission at the time directed MISO to conduct restudies on an as-needed basis only, even when a triggering event occurs. It said the RTO “could decide in its discretion whether a restudy was needed or not.”
In revisions filed last March, MISO altered its Tariff to enable it to conduct restudies for reasons other than triggering events. In the most recent ruling, FERC reversed that move, saying the RTO cannot conduct a restudy absent a trigger.
FERC accepted several other smaller Tariff revisions that it had directed MISO to make, including:
Stipulating mandatory attendance of transmission owners in scoping-level meetings between MISO staff and interconnection customers;
Describing the types of events that trigger a queue restudy; and
Offering customers a provisional generator interconnection agreement option at any time in the interconnection process, regardless of whether MISO failed to meet a study deadline.
MISO was also required to scale back its site control requirement by the queue’s second decision point from 100% to 75% after FERC determined that complete site control is difficult to obtain so early in the process.
The RTO also had to clarify that an interconnection customer that withdraws early in the queue — at either the first or second decision points — will not be responsible for the costs of other customers’ interconnection studies, and that a customer withdrawing at the third decision point should only pay a study deposit fee to cover a potential restudy for another interconnection customer.
Finally, MISO added language to clarify that the batch of projects entering the definitive planning phase in August 2015 was grandfathered into the old queue design.
However, FERC’s recent ruling gave the RTO 30 days to clarify that the queue’s third and fourth $4,000/MW milestone payment collection is only an initial charge subject to change as costs become clearer in the study process.
“This language implies that the M3 and M4 milestone payments are set to $4,000/MW and are not subject to a true-up as more accurate estimates become available, which is not in line with MISO’s indication in its testimony,” FERC said.
In accepting MISO’s filing, FERC dismissed a bundle of complaints from EDF Renewable Energy as being outside the scope of the proceeding. EDF had asked FERC to force MISO to share more network modeling details and prescribe “remedies” should the RTO fail to complete studies on time. The company also sought a directive instructing MISO to develop a fast-track queue option for vetted projects, and complained that the RTO failed to coordinate its generator interconnection process with the transmission planning process.
Avangrid announced Friday that Massachusetts has selected the transmission project of its subsidiary, Central Maine Power, as the alternative for the state’s 9.45-TWh clean energy solicitation if New Hampshire regulators do not approve the Northern Pass transmission line by March 27.
Massachusetts awarded the contract to Eversource Energy and Hydro-Quebec’s Northern Pass on Jan. 25, only to see the New Hampshire Site Evaluation Committee (SEC) unanimously reject the 1,090-MW transmission project a week later. Eversource appealed the decision, saying in a statement Feb. 16: “We have a strong legal argument for a reconsideration by the SEC.” (See New Hampshire Rejects Permit for Northern Pass.)
| Eversource, Central Maine Power
CMP and Hydro-Quebec’s New England Clean Energy Connect (NECEC) transmission project would deliver up to 1,200 MW of Canadian hydropower to the New England grid via a 145-mile transmission line. The partners estimate the project to cost $950 million.
News of the selection drew a protesting tweet from Dan Dolan, president of the New England Power Generators Association: “Massachusetts is now all-in on Hydro-Quebec, going from the fatally flawed Northern Pass to a Maine project that still lacks virtually all its key permits. Hydro-Quebec is asking for Massachusetts consumers to guarantee them revenue through an above-market contract for electricity for the next two decades.”
Hydro-Québec Major Facilities | Hydro-Québec
Dolan said existing power plant operators in the region have invested more than $13 billion in their plants without any guarantee of cost recovery or profit.
Beginning Negotiations
CMP submitted applications for state and federal permits for NECEC in mid-2017 and said it expects to receive state approvals later this year and final federal permits in early 2019. The company said it will immediately begin negotiation of long-term contracts with the Massachusetts electric distribution companies to prepare for a submission to the state’s Department of Public Utilities in April 2018.
“Our applications for state and federal permits are moving forward with the strong support of communities and stakeholders in Maine,” CMP CEO Doug Herling said in a statement.
Eversource’s statement said that Friday’s decision “strikes a sensible balance by allowing negotiations with Northern Pass to continue, while establishing a back-up protocol that can be initiated if necessary.”
Avangrid Networks CEO Bob Kump said, “A new transmission link between Maine and Quebec would deliver a reliable, firm supply of clean energy to help dampen seasonal price instability when high demand puts pressure on natural gas supplies.”
Massachusetts issued its MA 83D solicitation for hydro and Class I renewables (wind, solar or energy storage) last July. The selection committee for the clean energy request for proposals issued in July 2017 includes representatives from the state’s Department of Energy Resources and from distribution utilities Eversource, National Grid and Avangrid subsidiary Unitil.
Any contract awarded under the request for proposals must be negotiated by March 27 and submitted to the DPU by April 25.
Other proposals for the RFP included Nova Scotia-based Emera’s Atlantic Link project, a 375-mile submarine HVDC transmission line from New Brunswick to Plymouth, Mass., to deliver 5.69 TWh of clean energy per year. National Grid partnered with Citizens Energy on two transmission projects; one of them, the Granite State Power Link, is a 59-mile HVDC line from northern Vermont to New Hampshire to deliver 1,200 MW of new wind power from Canada.
The state-owned Hydro-Quebec also partnered separately with Transmission Developers Inc. for the RFP and, as with Northern Pass, made two proposals, one pure hydro and one with a wind energy component.
FERC last week ordered the shutdown of a Michigan hydroelectric project over longtime safety violations — the most significant of which relate to inadequate spillway capacity.
The commission will revoke the license for Boyce Hydro’s 4.8-MW Edenville Dam in northern Michigan on March 1 following its Feb. 15 cease generation order and denial of the company’s request for rehearing on the issue (10808-058).
FERC dismissed Boyce’s arguments that the commission didn’t consider corrective measures the dam had already taken; that it doesn’t have authority to order a dam to shut down; and that the cease generation order was arbitrary and capricious. FERC has been threatening to close Edenville since late last spring.
The commission last month gave Boyce until March 1 to correct violations, some of which that have persisted since 2004, including:
Failing to increase spillway capacity to address the increased likelihood of more frequent flooding;
Performing unauthorized dam repairs and excavation;
Neglecting to file a public safety plan or follow its own water monitoring plan; and
Failing to acquire all property rights and to construct required recreation facilities near the dam.
FERC has repeatedly told Boyce to construct two auxiliary spillways to reduce the risk of flooding, “a grave danger to the public,” the commission wrote.
“Boyce Hydro’s license includes terms and conditions concerning dam safety, property rights, water quality, public recreation and safety, and other areas of public concern,” the commission said. “Boyce Hydro has a long history of noncompliance with those terms and conditions … [and] failed to comply … except for the obligations to acquire and document certain property rights (although the lack of designs for the new and revised spillways makes it difficult to determine if it has acquired all necessary property rights).”
Edenville Dam spillway
The commission in January granted Boyce a temporary stay of shutdown until the beginning of March so the company can use the dam’s powerhouse to pass flows to alleviate ice formation on spillway gates during winter. (See Michigan Dam Faces Shutdown over Longtime Safety Concerns.)
FERC said Edenville’s current spillway can only currently handle 50% of a probable maximum flood.
The commission ordered Boyce last year to file plans to construct spillways and provide public access and recreational facilities by late 2017, but the filings never materialized, it said. Although Boyce had hired an engineering firm to design a new spillway and promised to create an escrow account for 50% of its gross revenues to fund construction, FERC found those plans insufficient, saying that it would take the company two years to save enough money to fund spillway construction.
“Given that the public has already been at risk for more than 13 years due to the licensee’s refusal to remediate the project spillways, we cannot accept a proposal that will perpetuate the problem even longer,” FERC said.
The commission expressed disbelief that Boyce’s lengthy history of noncooperation would change now.
“After weighing the relevant factors, commission staff determined that the violations required prompt action and that the licensee’s persistent pattern of noncompliance provided strong evidence that it would not make serious efforts to come into compliance absent an order disrupting its operation,” the commission wrote.
FERC said it didn’t take the economic impacts of a shutdown lightly but said the move is “a situation of Boyce Hydro’s own making.”
Boyce can seek a rehearing of the order before a FERC administrative law judge within 30 days.
A distributed energy resource trade group is calling on MISO to open its markets to customer-owned demand response and urging state regulators and utilities to develop programs that reimburse small DR providers.
The Advanced Energy Management Alliance (AEMA) last week issued a white paper containing model Tariff language intended to extend access to MISO’s wholesale markets to customer-owned demand-side resources.
The white paper suggests that states in the RTO’s footprint adopt DR programs like those in New York and the portion of Indiana in PJM.
| Advanced Energy Management Alliance
“While not new to the Midwest, the growth and development of demand response in the region has largely stagnated,” AEMA wrote. “To create shared value for utilities and consumers, states should take near-term action to create robust demand response programs where demand response is lacking and evolve demand response program design in territories that have had the same tariffs for over a decade.”
Like in the PJM area of Indiana, AEMA suggests having utility-qualified DR providers register their customers with a utility, which would then enroll the customers in MISO’s DR program. The utility would receive capacity credit for customers they enroll, and DR providers would get either an average price from MISO’s annual capacity auction or 35% of the net cost of new entry. AEMA said the approach would be “an effective means for stimulating cost-effective DR while working within existing state and MISO market constructs.”
As an alternative, AEMA said MISO could adopt New York-style programs that concentrate on reducing transmission and distribution costs and stay independent of wholesale capacity programs.
The organization also said that if states agree, MISO could devise Tariff rules for peak load management, distribution-level services and, eventually, additional wholesale market programs.
AEMA also suggested that Midwestern states allow bilateral contracting between utilities and DR providers. Under this scenario, the utility and the provider contract for a specific number of megawatts for enrollment, a price per megawatt and program design — including the terms of dispatch.
“AEMA is eager to collaborate with MISO-based utilities, regulators and system operators in this endeavor. Our goal is not to overturn existing bans that prohibit demand response providers from directly enrolling customers in wholesale market programs, but instead to develop new creative approaches to exploiting the full potential of demand response,” the group said.
It said new DR resources are less expensive than running aging generation.
“Energy leaders in the Midwest should not let excess capacity stop them from pursuing all cost-effective demand response,” the organization said.
AEMA Executive Director Katherine Hamilton said the white paper is a “roadmap” for state regulators and utilities.
“We hope that this white paper is used as intended — to inform and offer options for regulators and utilities seeking to partner with third-party providers and consumers. AEMA members seek to grow our businesses while giving consumers additional choices and providing cost-effective, environmentally sustainable services to the electric grid,” Hamilton said.
Several utilities in MISO states have interruptible DR programs, but AEMA said those programs need to evolve.
MISO had 10.7 GW of wholesale DR capacity in 2016, 8.9% of its annual load peak. The RTO’s DR is mostly derived from interruptible load and behind-the-meter generation under state-regulated and utility-run programs and accredited as load-modifying resources or emergency demand resources.
FERC last week authorized an ITC Holdings subsidiary to purchase transmission assets from a small southwestern Michigan city.
The ruling authorizes Michigan Electric Transmission Co. to spend $201,206 to buy transmission assets at the Black River Substation from the City of Holland Board of Public Works (EC18-21). The assets include surge arrestors, relay panels, circuit breakers, backup relays and disconnect switches that Michigan Electric plans to use in its transmission operations.
ITC transmission | ITC
The commission said the acquisition was consistent with the public interest and won’t hinder competition in the area. Michigan Electric has also pledged to hold all transmission customers harmless from any transaction costs for five years.
“The proposed transaction does not involve any change in ownership or control of any generating facilities. Accordingly, the proposed transaction will not have any impact on concentration in any relevant market,” FERC said. The commission also said that prior experience suggests that sales involving only the transfer of transmission facilities are unlikely to result in uncompetitive activity.
FERC last week declined to grant Ameren additional transmission incentive rates for portions of the company’s 500-mile Grand Rivers project in Illinois and Missouri.
Ameren sought a 100-basis-point incentive adder for the return on equity for the Illinois Rivers and Mark Twain components of the project, which is intended to create a continuous 345-kV path from Iowa to Indiana. The company also requested authorization to assign the incentive to any affiliate that undertakes the development, construction or ownership of those portions of the project.
Grand River Project | Ameren
The commission said the segments were already too far developed to be considered risky enough for incentive rate treatment (ER18-463).
“We find that, due to the late stage of … development, including the substantial completion of the Illinois Rivers component, Ameren Transmission has failed to demonstrate that the remaining risks and challenges associated with the components warrant the requested ROE incentive,” the commission sad. “A project that is further along in construction and thus closer to completion typically faces fewer remaining risks and challenges, and we find that is true here.”
FERC agreed with the contention by the Organization of MISO States and the Missouri Public Service Commission that Ameren had already spent 77% of its cost estimate on the two lines when it asked for the rate incentive in mid-December, when permitting risks were minimal and already covered by a previously approved abandonment incentive. Ameren had argued that the two lines face “unprecedented” risks that are not covered by its other rate incentives.
The commission has previously granted several incentives for the Grand Rivers Project, including 100% construction-work-in-progress recovery, abandoned-plant recovery, a hypothetical capital structure and the authority to assign incentives to affiliated entities.
New generators seeking interconnections must be equipped to provide primary frequency response, FERC ruled Thursday (Order 842, RM16-6).
The commission said the requirement that generators have governors or other equipment to respond automatically to frequency disturbances must be included in the pro forma generator interconnection agreements (GIAs) for both large (20 MW+) and small generators.
The rules will apply to new generation and existing generators that seek a new interconnection agreement because of “material modifications” to their facilities. The commission declined to order existing generators to retrofit their facilities to provide the service, saying it would be “prohibitively expensive” for some.
The final rule makes only small changes from the commission’s November 2016 Notice of Proposed Rulemaking, which cited concerns by NERC and others that frequency response has declined with the loss of traditional synchronous generation and the increase in asynchronous renewables. (See FERC: Renewables Must Provide Frequency Response.)
The commission cited a 2010 NERC survey that found only 30% of generators in the Eastern Interconnection provided primary frequency response and that only 10% provided “sustained” response. The commission said the existing pro forma large GIA — which required primary frequency response from only synchronous generating facilities — does not reflect technological advances allowing nonsynchronous generation to provide the service.
The commission set operating requirements of a maximum droop setting of 5% and a deadband setting of ±0.036 Hz.
“We find that the establishment of minimum uniform operating requirements for all newly interconnecting generating facilities is preferable to the fragmented and inconsistent primary frequency response settings currently in place throughout the Eastern and Western Interconnections,” FERC said. ERCOT already has minimum frequency response requirements, FERC noted.
FERC agreed with recommendations by the Edison Electric Institute and the Western Interconnection Regional Advisory Body that it modify the rule to explicitly prohibit interconnection customers from blocking their governors’ ability to respond to frequency deviations.
“One of the commission’s concerns with the current lack of clear, uniform primary frequency response requirements is NERC’s finding indicating that a number of generator owners/operators have implemented operating settings that have effectively removed the availability of their generating facilities from providing timely and sustained primary frequency response (e.g., wide deadband settings, uncoordinated plant-level controls). The reforms adopted in this final rule, to be applied uniformly to new generating facilities, are intended to eliminate these practices.”
The commission disagreed with the National Rural Electric Cooperative Association’s (NRECA) contention that the rule is premature, saying “adopting these requirements now is more prudent than waiting until the lack of primary frequency response undermines grid reliability, a point acknowledged by NERC’s Essential Reliability Services Task Force.”
Headroom, Compensation
The commission rejected EEI’s proposal that generators be required to maintain headroom — allowing them to increase output in response to low frequency — and receive compensation for doing so. “If future conditions necessitate a headroom requirement, we will then consider any appropriate compensation,” it said.
FERC also said it would consider on a case-by-case basis requests from transmission providers seeking to impose a headroom requirement “in a particular factual circumstance” that includes a compensation mechanism.
The commission said compensation is not necessary because “the cost of installing, maintaining and operating a governor or equivalent controls is minimal.” FERC estimated the cost of adding governors to new wind and solar generators would average $3,300/MW, about 0.2% of total capital costs for wind and solar.
FERC also rejected requests that it order compensation for traditional generators that provide inertial response. “No commenter asserts that inertial response trends on the Eastern and Western Interconnections are approaching levels that could threaten reliability. In addition, because inertial response is provided automatically by the rotating mass of synchronous machines as system frequency deviates and is not controllable, synchronous generating facilities do not incur additional incremental costs to provide inertial response,” the commission said.
Exceptions and Accommodations
The commission exempted or offered accommodations to some classes of resources:
Combined heat and power (CHP) generators that are sized to serve onsite load and have no ability to export power to the grid will be exempt from the operating requirements but must install a governor “in the event that there is an increased need in the future for primary frequency response capability.”
Energy storage will only be required to provide frequency response within specified operating ranges representing minimum and maximum states of charge. The commission said the accommodation would prevent the premature degradation of storage resources.
Distributed energy resources will be required to provide frequency response only when they are allowed to ride through disturbances, the commission said in response to Xcel Energy’s concern that dynamic frequency response at the distribution level can interfere with anti-islanding protections. The rule does “not supersede a generating facility’s ride-through settings or require an interconnection customer to override anti-islanding protection or any protective relaying that has been set to disconnect the generating facility during certain abnormal system conditions,” the commission said.
Nuclear generators are exempt from the rule because their licenses with the Nuclear Regulatory Commission often restrict providing frequency response.
No Exemption for Wind, Small Generators
Wind generation must comply with the requirement, the commission said, rejecting an exemption request by Sunflower Electric Power and Mid-Kansas Electric.
“Unlike certain CHP or nuclear generating facilities, the record does not indicate that there is an economic, technical or regulatory basis for a generic exemption for newly interconnecting wind generating facilities,” FERC said. “In particular, we are persuaded by [the American Wind Energy Association’s] assertion that the proposed primary frequency response capability requirements can be met at low cost for new wind projects, and that newly interconnecting wind facilities should not have difficulty complying.”
Small generators also will not be exempt. The commission said the rule will not result in “unduly burdensome” costs or create a barrier to entry, noting that PJM has not seen a decrease in small generator interconnections since it required nonsynchronous generation to install enhanced inverters with frequency response capability. “We are persuaded by commenter assertions that that small generating facilities are making up a growing percentage of the generation resource mix, and that as the market penetration of small generating facilities increases, there will be a growing need for primary frequency response from these generating facilities,” FERC said.
The commission rejected NRECA’s request that individual balancing authorities be permitted to seek waivers from the rule but agreed that “unique circumstances or needs of some individual regions or areas may warrant different operating requirements.” FERC said it would consider variations based on Regional Entity reliability requirements; variations that are “consistent with or superior to” the final rule; and “independent entity variations” filed by RTOs and ISOs.
The revised GIAs are due 70 days after publication of the rule in the Federal Register.
ISO-NE could see substantial “spillage” of renewable energy and large price separations because of transmission constraints under scenarios considered in the RTO’s 2017 Economic Study, officials told the Planning Advisory Committee on Wednesday.
The study was requested by the Conservation Law Foundation to evaluate scenarios for meeting Massachusetts and Connecticut climate laws and the Regional Greenhouse Gas Initiative’s emission caps.
The study was based on the “Renewables Plus” scenario from the 2016 Economic Study, which modeled the year 2030 — the only scenario in the 2016 study to meet the RGGI cap. (See Study: New Resources Could ‘Crowd Out’ Old in ISO-NE.)
| ISO-NE
Under Renewables Plus, the generation fleet met existing renewable portfolio standards, and new renewable or clean energy resources were added above existing RPS requirements.
The new study looked at three additional scenarios:
“EE + Offshore”: Added more energy efficiency and offshore wind while reducing imports from Canada by 1,000 MW.
“Onshore Less EE/PV”: A variation on the business-as-usual base case from the 2016 report, with onshore wind boosted to 7,000 MW (nameplate capacity) from 4,800 MW in the reference case.
“Wind Less Nuc”: Assumes the Millstone nuclear plant retires by 2030, five years ahead of its license expiration, with the gap filled by renewable/clean energy resources.
The study found all three scenarios met projected demand, even with transmission constraints based on the “as-planned” system’s internal and external transfer limits.
If transmission constraints are not relieved, the RTO would see “spillage” of wind power north of the Surowiec-South interface, leading to lower prices in Northern Maine than southern New England. For example, under the constrained scenarios, 7 to 18% of renewables would be spilled, with 22 to 89% of the spillage north of Surowiec-South.
In the constrained Wind Less Nuc scenario, average LMPs would range from $13.78/MWh in the Bangor Hydro Electric subarea in northeastern Maine, to $38.71/MWh in the NH subarea (which includes most of New Hampshire, eastern Vermont and southwestern Maine) and $37.18/MWh in Boston.
Only one scenario, EE + Offshore, is as good as the Renewables Plus scenario in meeting the RGGI 2030 emission targets. | ISO-NE
Electric production by natural gas plants fluctuates with assumptions regarding plant retirements and price-taking offers ($0/MWh) by renewable resources. EE + Offshore has the least gas-fired energy, while Wind Less Nuc has the most gas production, especially when the transmission system is constrained.
EE + Offshore had the lowest total production costs, coming in 28% below the Renewables Plus reference case assuming transmission constraints. Onshore Less EE/PV had the highest costs, 77% above the constrained reference case.
Only one scenario, EE + Offshore, is as good as the Renewables Plus scenario in meeting the RGGI 2030 emission targets.
CLF staff attorney David Ismay said the two emission-reduction targets, which were also used in the 2016 study, were intended to “bracket” the goals RGGI might embrace in its latest program review. RGGI’s emissions cap declines by 2.5% annually through 2020. The group announced in August that it would seek an additional 30% reduction in emissions from 2020 levels.
“We expressly worked … to design all three scenarios to meet [RGGI] emissions targets,” Ismay said.
“We’re starting to get a better picture of what the grid needs to look like in order to meet our climate laws and emission regulations that are already on the books,” he explained in an interview later. “We really need a grid that’s different from what we have now. I think that will give legislators, regulators and the ISO information on the kind of mix we need to comply with these laws. … It’s really helpful to see the impact of adding 1,000 MW of EE or 1,000 MW of wind.”
Stakeholders have until April 2 to submit requests for additional economic studies. Requests should be emailed to PACMatters@ISO-NE.com.
MISO is embarking on a review of its entire economic planning process in an effort to more accurately capture the benefits of cost-shared transmission projects.
“This is not about MISO saying the existing process is broken or flawed,” Matt Ellis, of the RTO’s Economic Planning Users Group, told stakeholders at a Feb. 13 Planning Subcommittee meeting.
Ellis said MISO is looking forward to FERC-level discussion on best practices for planning and that it will continue to talk about economic models throughout 2018.
MISO especially wants to take a fresh look at:
The economic impacts of transmission outages;
Voltage and local reliability resource commitments, especially in MISO South load pockets where performance has lagged;
MISO’s emergency energy supply and how it’s being valued in economic models when it defers transmission and generation investment or prevents scarcity pricing and loss-of-load events;
Accounting for likely import and export flows in adjusted production costs; and
Forecasted renewable resource ownership and which members will actually purchase the energy and benefit when considering renewable portfolio standards.
Further, the RTO plans to hold stakeholder discussions through June on other possible measurable benefits that could be valued in the modeling of market efficiency projects. It could consider such benefits as the deferral of reliability projects; savings that could arise from opening up it contract flow path with SPP that bridges MISO South and Midwest; reduced transmission energy losses; reduced ancillary services costs; and deferral of capacity expansion stemming from increased capacity import/export limits.
| MISO
Ellis asked for member companies’ engineers to come forward with other ideas about overlooked benefits of market efficiency projects that could be assigned a monetary value.
Minnesota Public Utilities Commission staff member Hwikwon Ham cautioned that renewable standards are set by state legislatures and can be changed. Ellis responded that MISO is looking for that kind of information and other input.
He also said timely changes to MISO’s modeling could affect how it judges potential projects in its annual Market Congestion Planning Study for the 2018 Transmission Expansion Plan.
“We are fully aware that having a process review in parallel with having the process is not an ideal situation. It introduces a lot of ‘what-ifs,’” Ellis said. He promised that MISO would test any projects affected by an economic model change using both the old and new models and that it could delay implementing the new aspects of economic modeling.
MISO announced its plan the same week it proposed to lower the voltage threshold for market efficiency projects to 230 kV, and two weeks after FERC ordered a technical conference on how PJM, MISO and SPP coordinate generator interconnection studies after developer EDF Renewable Energy complained that the RTOs’ modeling standards violate the FERC requirement for transparent open access interconnection service. (See FERC Orders Review of PJM, MISO, SPP Generator Studies.)
Consolidated Edison’s fourth-quarter net income increased 144% to $505 million ($1.63/share) from $207 million ($0.68/share) in 2016, the company said last week.
Total revenue for the quarter increased 9.38% to $2.961 billion.
The company reported 2017 net income of $1.525 billion ($4.97/share), compared with $1.245 million ($4.15/ share) in 2016. Total revenue was down slightly in 2017 but remained above $12 billion.
Con Edison Composition of Regulatory Rate Base as of Dec. 31, 2017 | ConEd
Con Ed said its adjusted earnings for 2017 excluded the remeasurement of deferred tax assets and liabilities upon enactment of the federal Tax Cuts and Jobs Act, the effects of the gain on the sale of a solar electric production project, and the net mark-to-market of Con Edison’s clean energy businesses.
The company’s earnings presentation showed the new law reduced the net deferred tax liabilities for its Con Ed of New York, Orange and Rockland Utilities and Rockland Electric subsidiaries by more than $5 billion collectively.
Con Ed plans to meet its 2018 capital requirements through internally generated funds and the issuance of securities. The company’s plans include issuing between $1.3 billion and $1.8 billion of long-term debt at its utilities and additional debt secured by its renewable electric production projects.
The company also plans to issue up to $450 million of common equity in addition to equity under its dividend reinvestment, employee stock purchase and long-term incentive plans. The plans do not reflect the provision to utility customers of any tax law benefits that may be required by the New York Public Service Commission or the New Jersey Board of Public Utilities.
