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November 7, 2017March 25, 2025

FERC May Consider Hydro License Changes

By Rich Heidorn Jr.

FERC may consider additional changes to its hydropower licensing rules following a review prompted by President Trump’s March 2017 executive order to eliminate burdens on domestic power production.

Executive Order 13783, “Promoting Energy Independence and Economic Growth,” required executive branch officials to review their regulations, orders and policies and eliminate those that “unduly burden the development of domestic energy resources.”

On Nov. 1, FERC published in the Federal Register a 30-page report in response, saying it had found several potential changes involving its hydropower rules that the commission may consider. Commission staff emphasized that, as an independent agency, it was not required to respond to the order but was doing so voluntarily.

The report said “the vast majority of agency actions relating to the commission’s hydropower program do not present a material burden.”

But it said the commission “could consider” revising its regulations to:

Make optional the integrated licensing process (ILP), which is currently the default — requiring applicants to justify the use of the traditional licensing process or the alternative licensing process;
Make optional the requirement to submit a draft license application or preliminary licensing proposal before submitting a final license application as part of the prefiling process;
Reducing comment and filing deadlines to save three months in the three- to three-and-a-half-year process for obtaining an integrated license;
Increasing the threshold — currently 5 MW — for eligibility for the “simplified and expeditious licensing procedure for small hydroelectric power projects” under the Public Utility Regulatory Policies Act;
Removing the requirement that facilities eligible for license exemptions under PURPA Section 405 install or increase the capacity of their facilities;
“Explicitly” allow applicants for small hydropower exemptions to convert their exemption applications to a license application if the exemption is rejected; and
Allow hydro operators whose license applications are rejected to resubmit their applications once the deficiencies are corrected.

Next Steps up to Commission

FERC spokeswoman Mary O’Driscoll emphasized that the response is a FERC staff report. “The commission itself will determine what steps to take on any and all matters related to this,” she said in an email. “We cannot predict, nor can we surmise, what the commission will do in the future.”

The response to the executive order also says the commission “currently is considering comments” on its policies on the length of hydropower licenses, an apparent reference to the responses to its 2016 Notice of Proposed Rulemaking (RM17-4).

FERC ISO-NE Hydropower President Trump licensing

Kerr Dam in Montana

O’Driscoll explained that the staff response was due Sept. 27, before the commission’s Oct. 19 meeting, at which it approved a policy statement setting a 40-year default license term. The commission said the change will reduce administrative costs and encourage dam owners to upgrade capacity and make environmental or recreational investments (PL17-3). (See FERC Sets 40-Year Term for Hydro Licenses.)

Prefiling Requirement for LNG Terminals

Commission staff also reviewed but found no rules to recommend changing regarding LNG terminals; natural gas pipeline and storage facility siting; generator interconnection policies; and electric capacity markets in PJM, ISO-NE and NYISO.

For example, staff examined the prefiling process for LNG terminals and related facilities but ultimately decided “there is no need for the commission to consider any revision.”

Commission regulations require applicants to use its prefiling process for at least 180 days before filing an application. Staff said that although the Natural Gas Act only requires prefilings for terminals and not “related” facilities, gas pipelines and the terminals they serve need to be evaluated together to avoid segmentation under the National Environmental Policy Act.

“Further, the prefiling process allows stakeholders to become involved in the overall project at an early stage, and applicants can benefit from stakeholders’ early identification and resolution of issues that may overlap with the LNG terminal. Without using the prefiling process for related jurisdictional natural gas facilities, delays could occur during the application review, when issues are first identified and need resolution,” staff said. “Thus, although this regulation may result in delays or additional costs to the applicant early on in a project’s development, its overall result is a more timely application review.”

November 7, 2017

CEOs See Dollar Signs in ZECs, PJM Price Formation

By Rory D. Sweeney

The CEOs for three of the largest companies that stand to gain from proposed price supports for nuclear and coal generators used their third-quarter earnings calls last week to praise FERC, the Department of Energy, PJM and states for their attention to the issue.

price formation exelon pseg dominion earnings q3 — Crane | © *RTO Insider*

Exelon’s Chris Crane, Public Service Enterprise Group’s Ralph Izzo and Dominion Energy’s Thomas F. Farrell II all made a point to thank the RTO, states or federal agencies who have made — or are considering — changes to funnel additional money to the generators, which the companies argue are critical to the grid but undervalued in markets.

And they had good reason to. Crane said “each dollar [per] megawatt-hour of distortion caused by a flawed market design” costs the company $135 million per year. Izzo said each dollar change in per-megawatt-hour revenue from PJM is worth $55 million pre-tax to his company.

“We commend [Energy Secretary Rick Perry] for focusing attention on the need to reform the energy markets, and ensure that our customers continue to benefit from the resilient system,” Crane said. “Between these efforts and state initiatives, we’re optimistic about the path to preserve nuclear power plants. … We are confident that the FERC actions around resiliency will facilitate needed power price reforms in PJM that will fairly compensate our generating assets.”

The DOE’s Notice of Proposed Rulemaking “is aimed at protecting our customers from outages resulting from manmade and natural interruptions on the gas system by preserving resilient generation sources, including nuclear,” he said.

PSEG is “on track … to reduce the all-in cost per megawatt-hour of its nuclear operations by 10% from the average cost experienced during the prior three years,” Izzo said. “But energy prices influenced by the availability of natural gas have declined by a greater degree during this time frame.

“We believe that the DOE NOPR is necessary. … We recommend that measures adopted in response to the DOE NOPR should be viewed as an interim [solution] until effective mechanisms can be developed that recognize these attributes in the market,” he said. “State action also remains critical to prevent the loss of these units. We believe state action can be done [in a] way that both maintains the integrity of the wholesale market and serves as a bridge until a regional [or] federal solution is in place.”

State ZEC Programs

Farrell didn’t want to speculate on the outcome of the NOPR, but said “Connecticut certainly hasn’t been willing to depend on it.” He said he expects Connecticut lawmakers to follow Illinois and New York in establishing a zero-emission credit program to support nuclear units.

Last week, Gov. Dannel Malloy signed a bill that could allow Dominion’s Millstone nuclear plant in Waterford, Conn., to compete in a state-sponsored solicitation for zero-carbon electricity if officials conclude it is in the best interest of ratepayers. Malloy, however, said he believes the plant is profitable and does not need a subsidy.

“Dominion Energy thanks the general assembly for giving Millstone this opportunity and is grateful to the Malloy administration for his work in negotiating the current form of the legislation,” Farrell said.

“We weren’t surprised” by approval of the legislation, he added. “We’ve been working on it for two years and been deeply involved in it for that period of time.”

Joe Dominguez, Exelon’s vice president of governmental and regulatory affairs and public policy, also praised the Connecticut legislation and said that his lobbying efforts aren’t done.

“We have been [in] very productive discussions both in Pennsylvania and New Jersey. We’ll continue to do that,” he said.

He said that the ZEC programs are designed to decrease if energy-market reforms happen, so “it will not be a double-dip here.”

Izzo said PSEG is lobbying as well.

“Depending on what happens at the federal level, there remains the opportunity for New Jersey to recognize certain attributes that perhaps are not explicitly identified at the federal level,” he said. “We are just in a series of conversations with people right now. We are just making sure they understand what our nuclear plants mean to New Jersey.”

FERC Action

Izzo and Crane agreed FERC should order PJM to revise its price formation methodology, a move Izzo called a “no brainer” and “long overdue.” Crane anticipated changes by as early as mid-2018.

In its comments to FERC on the NOPR, PJM suggested such reforms in arguing that large, inflexible units should be able to set LMPs. (See Critics Slam PJM’s NOPR Alternative as ‘Windfall’.)

Defining “resiliency” has been an ongoing debate, but Dominguez said PJM’s Capacity Performance design makes the discussion quantitative.

“We were able to value the cost of incremental reliability associated with dual fuel, so if the design basis ultimately ends up being we need 90 days of fuel, we have a mathematical way of calculating what’s the market solution to get dual-fuel resources to 90 days of fuel with it,” he said. “That would probably be $8 or $10/MWh in terms of doing that based on the cost we saw in CP.”

A rule from FERC that boosted power prices could also leave smaller retail competitors who have been “aggressive” in their pricing vulnerable to acquisitions by large, integrated energy companies like Exelon, Crane said.

“Any time we’ve seen a volatility event … we’ve had opportunities to acquire companies in that type of environment,” Crane said.

Izzo said he was wary of projections that rules on price formation will increase PJM energy prices by $2 to $4/MWh, saying it ignores other factors that can have an impact.

“What [is the impact] of pipelines that may change the basis differential of gas in Western PJM versus Eastern PJM? What [is the impact of] future carbon constraints that may or may not be part of a subsequent administration in Washington?” he said. “Some people on this call may want to go see their children in their Halloween parades; otherwise I would list a thousand other factors that should go into people’s thought process before making those kind of investment decisions.”

Earnings

Crane said the Illinois Power Authority’s decision last month to delay the finalization of the procurement of the ZEC contracts from December 2017 to January 2018 will shift 9 cents of earnings per share from 2017 to 2018.

Exelon earned $824 million ($0.85/share) in the third quarter, missing expectations by 1 cent but improving on the 53 cents/share earned in the same quarter a year ago. Revenue of $8.77 billion beat expectations by $90 million but was down from $9 billion a year ago. Operating earnings were 85 cents/share, compared to 91 cents/share for the third quarter of 2016.

While Exelon hasn’t escaped the industry’s cyclical nature, “we’ve gained greater flexibility with programs like the ZEC,” Crane said.

Dominion posted operating earnings of $672 million ($1.04/share) for the third quarter of 2017, which beat expectations by 2 cents but was down from $716 million ($1.14/share) for the same period in 2016. Revenue of $3.18 billion missed expectations by $110 million but was up from $3.13 billion in the third quarter of 2016.

PSEG reported third-quarter operating earnings of $417 million ($0.82/share), which missed estimates by 2 cents and was down from $444 million ($0.88/share) a year ago.

Seeking Alpha provided the earnings calls transcripts for this article.

November 7, 2017

AMP Questions $400M in Added PJM Tx Upgrades

By Rory D. Sweeney

PJM’s announcement on Thursday of plans to recommend more than $400 million in transmission upgrades — just weeks after the RTO’s Board of Managers authorized $1 billion in spending — sparked pushback from American Municipal Power, which said the RTO ignored questions about the effectiveness of several of the projects.

Staff plan to recommend adding the projects to PJM’s Regional Transmission Expansion Plan at the board’s Dec. 4 meeting.

AMP’s Ryan Dolan questioned PJM’s analysis of several of the reliability projects, arguing that the proposed solutions fail to address all issues at the nodes in question and will necessitate additional construction in the future. He was displeased that PJM plans to recommend the projects even though, he said, concerns were raised about their effectiveness from a “holistic planning” perspective at a sub-regional RTEP discussion the previous day.

“For some of these projects, basically … [PJM is] planning on making these recommendations no matter what comments were provided,” Dolan said. “I think it would be useful to give time between when we make recommendations to when the last review of a project is to ensure any of the comments … that were brought up … can actually be accounted for.”

American Municipal Power AMP transmission upgrades — Sims | © *RTO Insider*

PJM’s Mark Sims responded that all information underlying the RTO’s recommendation has been available throughout the planning process and that recommendations can change as additional information is added to the analysis.

“We’ve been transparent with all the steps along the way,” he said.

The $400 million in additional projects will be recommended as the result of a reliability analysis for the 2021/22 delivery year, Sims said. They include eight projects from the first RTEP proposal window for 2017, along with 13 projects that were previously identified.

transmission upgrades American Municipal Power AMP — Dumitriu | © *RTO Insider*

The recommendations also include one market efficiency project proposed by American Electric Power to address a thermal constraint on the Tanners Creek-Dearborn 345-kV circuit. PJM’s Nick Dumitriu explained that AEP’s $600,000 solution would upgrade equipment at the Tanners Creek station, removing price separation in the Duke Energy Ohio/Kentucky (DEOK) locational deliverability area in the 2020/21 Base Residual Auction Capacity Emergency Transfer Limit (CETL) study.

PJM rejected two other proposals for the same constraint that estimated costs at $4.9 million and $12.7 million.

RTO staff confirmed the upgrades will be included in the model for the 2021/22 BRA.

AMP has become increasingly critical of transmission spending in PJM. In September, the company released a report showing that more than half of the $24.3 billion in transmission spending in the RTO since 2012 were supplemental projects by transmission owners and were not needed to comply with RTO or federal reliability requirements. (See Report Decries Rising PJM Tx Costs; Seeks Project Transparency.)

November 7, 2017

MISO in ‘Good Shape’ for Winter Operations

By Amanda Durish Cook

CARMEL, Ind. — MISO expects to easily manage this winter’s anticipated 103.4 GW of peak demand with an estimated 142 GW of available capacity, stakeholders recently learned during a trio of meetings focusing on winter preparedness.

“We certainly can’t be complacent. … In winter, just like in every season, we have to be ready for anything thrown at us, but we’re prepared,” MISO Executive Vice President of Operations Richard Doying said during a Nov. 6 winter readiness workshop.

MISO peak demand winter reserve margin — Northern Indiana Public Service Co. crews make repairs after a late December storm in 2015 | *NIPSCO*

Using National Oceanic and Atmospheric Administration projections, MISO predicts this winter will be warmer than normal in its Central and South regions, while temperatures in the North region will be normal to below normal.

Darius Monson of MISO’s resource adequacy coordination group said the RTO’s winter reserve margin is expected to vary between 28.3 and 37.3% without factoring in outages.

“That’s a fairly good position to be in,” Doying said.

However, the reserve margin could range from 6.7 to 19.3% after taking possible outages into account, Monson said, compared with this year’s footprint-wide 15.8% planning reserve margin requirement. The RTO used historical outage data to predict winter outage levels anywhere from the more probable 23.3 GW, to 28.7 GW in a high load, extreme outage scenario. MISO might need to rely on behind-the-meter generation and demand response resources to meet peak demand under that scenario, Monson said.

The RTO does not predict any major constraints or thermal and voltage issues during the winter.

Engineer Katherine Hulet said MISO did not uncover any potential issues through its biannual Coordinated Seasonal Assessment. The study evaluates a variety of stressed conditions across the MISO footprint and identifies potential limitations and issues on the system for the upcoming winter.

Hulet said the RTO studied possible transmission contingencies, potential transfer contingencies, voltage stability and possible phase angle differences, but found no cause for concern.

“It really looks like MISO’s in pretty good shape. Not only are there capacity resources, but the transmission is in a position do well,” Reliability Subcommittee Chair Tony Jankowski said during a Nov. 2 conference call.

Jankowski asked if MISO is considering performing seasonal studies for shoulder periods. Hulet said seasonal studies will continue to be limited to summer and winter.

Jankowski urged operators to ensure all generators are in good repair. “Eventually that arctic air will make it into our footprint,” he warned.

Doying also said MISO is well-positioned for winter reliance on natural gas.

“We have access to just about all pipeline interconnections. Actually, most of the gas storage in the country is located within MISO,” Doying said during an Oct. 31 Markets Committee of the Board of Directors conference call. The RTO expects gas storage inventories nationwide to peak at 3.8 Tcf this winter, slightly below the five-year average, and prices to continue hovering around $3/MMBtu into winter.

Independent Market Monitor David Patton said MISO’s proximity to gas storage makes it easier to quickly ensure fuel supplies if a pipeline goes down, whereas the New England region doesn’t have such supply backups, requiring more Northeast generators to have dual-fuel capability.

“We’re ready until the next polar vortex presents a whole new realm of challenges,” MISO Chairman Paul Bonavia remarked jokingly.

November 5, 2017

FERC Approves ISO-NE Queue Clustering

By Michael Kuser

FERC last week approved ISO-NE’s proposal to cluster interconnection requests to relieve a backlog in the queue for northern and western Maine.

The revisions, effective Nov. 1, will allow the RTO to consider interconnection requests and allocated network upgrade costs in groups rather than individually.

The commission’s Oct. 31 order said that the changes “increase efficiencies, better inform the decisions of project developers and allow project developers to share the costs of the upgrades necessary to accommodate their interconnection” (ER17-2421). (See ISO-NE Files Cluster Study Rules; Window to Open in Nov.)

The RTO will use its new clustering procedure in addition to its “first-ready, first-served” serial interconnection request system. “When specific conditions are present in the ISO’s interconnection queue, the proposed methodology would allow two or more interconnection requests to be analyzed in the same system impact study and for developers to share costs for certain interconnection-related transmission upgrades,” ISO-NE said.

Together with the New England Power Pool’s Participants Committee and the Participating Transmission Owners Administrative Committee, the grid operator proposed implementing the clustering methodology first to address the queue backlog in Maine, where more than 5,800 MW of proposed resources, mostly wind, want to connect to the grid.

Long-Term Benefits

The commission rejected protests by RENEW Northeast, American Wind Energy Association, EDP Renewables and King Pine Wind, who argued it would be unjust and unreasonable to allow the clustering revisions to take effect before Massachusetts issues the results of its 2016 request for proposals. Owners of generation projects in northern and western Maine were among the respondents.

“Given the overall expected long-term benefits of the [revisions], we find that, on balance, it would be inappropriate to wholly reject the revisions to accommodate a subset of interconnection customers in the near term,” FERC said.

RENEW asserted that solicitations like Massachusetts’ determine which renewable generation projects are viable for interconnection construction and, thus, which projects execute power purchase agreements that include recovery of network upgrade costs. EDP said that ISO-NE could avoid such timing issues by aligning the implementation of the clustering with the timing of the Massachusetts RFP process.

NEPOOL responded that RENEW provided an alternative proposal in the stakeholder process to synchronize the interconnection cluster study process with the state’s energy procurement process, but only 40% of Participants Committee stakeholders favored the proposal.

The commission denied protesters’ request to delay implementation of the clustering revisions until 30 days after the results of the Massachusetts RFP are released. FERC also rejected protests that the misalignment between the cluster study process and state procurement processes would cause the first cluster to collapse because interconnection customers not selected for the RFP will withdraw from it. FERC noted that the RTO’s new rules “allow for full refund of the cluster participation deposit in such instances.”

The commission also was not persuaded by arguments that moving an interconnection customer that does not agree to join the cluster to the bottom of the queue is unjust and unreasonable.

“The clustering revisions appropriately aim to ensure that only those interconnection customers that are ready to move forward in the interconnection process participate in phase two of the cluster studies, [which] is consistent with the ‘first-ready, first-served’ approach that the commission discussed as a possible queue reform measure in RTO/ISOs as early as 2008,” the commission said.

November 5, 2017

FERC Approves CAISO Black Start Changes

By Jason Fordney

FERC last week approved CAISO Tariff changes to establish a process for selecting and procuring black start resources needed to restore segments of California’s transmission system in the event of regional outages.

Black start refers to the ability of a generating unit to begin operating without assistance from the electric grid. Such units are needed to restart other generation and restore the grid after widespread outages; they have certain requirements under the ISO’s Tariff.

CAISO FERC black start — CAISO needs additional black start capability in the San Francisco area

CAISO staff last year determined that additional black start capability was needed in the transmission-constrained San Francisco Bay Area, prompting staff to develop new procurement standards to be applied across the ISO. (See CAISO Board OKs Black Start, TAC Area, EIM Charter Measures.)

The changes reorganize and consolidate certain black start provisions, create rules for technical requirements and operating tests, and remove outdated provisions. They also designate the cost of incremental black start as a reliability cost and allocate it to the transmission owner in the area where the units are located (ER17-2237).

The new black start provisions entail significant involvement of the affected TO — in this case Pacific Gas and Electric — in drawing up technical specifications and vetting proposals from resources bidding into the solicitation. The ISO would have authority to accept or reject a TO’s recommended resources. PG&E supported the changes and cost allocation method.

Under the new rules, CAISO will use a cost-of-service approach to compensate selected resources, rather than provide a capacity-type payment sufficient to support the operation of an otherwise unprofitable generator.

FERC said the revisions improve the reliability and clarity of the Tariff.

“Because individual black start capacity resources do not benefit all parts of the system equally, it is just and reasonable to recover these costs from a participating transmission owner where the resource is located and serves the reliability need,” FERC said. No parties objected to the cost allocation, and the benefits were roughly commensurate with the costs, the commission said.

To comply with CAISO rules, black start generators must make a minimum number of starts, operate in standalone and parallel modes, be able to pick up load during start-up load, produce and absorb reactive power, and have communication and control equipment.

November 5, 2017

NRG Optimistic Despite Q3 Profit Decline

By Michael Kuser

A cool summer and the impact of Hurricane Harvey drove NRG Energy third-quarter earnings sharply lower, but the company still sees bright days ahead, according to CEO Mauricio Gutierrez.

NRG earned $171 million ($0.53/share) last quarter, compared with $402 million ($1.27/share) in the same period last year. Revenues were down 10.9% to about $3 billion.

Gutierrez said during a Nov. 2 earnings call that although the company is “on track” to transform itself through cost-saving measures, the third-quarter results led the company to lower its full-year earnings before interest, tax, depreciation and amortization (EBITDA) guidance to $2.4 billion to $2.5 billion from the previous $2.56 billion to $2.76 billion.

“In Texas we saw both a major hurricane and the coolest August since 2004, with cooling degree days 13% below normal, and in the Northeast, cooling degree days were on average 8% below normal for July and August,” Gutierrez said. He noted that ERCOT summer wholesale prices fell 43% below expectations. Mild weather across the East and in Texas eliminated any opportunity to benefit from scarcity pricing.

NRG attributed one-time financial impacts of $40 million to Hurricane Harvey, evenly divided between its generation and retail operations in Texas. About 80% of the company’s baseload generation on the Gulf Coast was available during the worst part of the storm, and 95% has been restored to date.

Brighter Side

NRG’s retail business continues to improve its operating efficiencies, customer acquisition and retention, which partially offset the impacts of milder summer weather, especially in ERCOT, Gutierrez said.

He said certain cost and margin enhancements will start impacting the company’s bottom line next year, as well as the sale of subsidiary NRG Yield and its renewables assets, which is expected to be completed this year and return up to $4 billion. The company continues to use excess cash to deleverage itself, he said.

“Since our second-quarter call, we have taken another $600 million of debt out of our capital structure, completing our 2017 capital allocation,” Gutierrez said.

He also pointed to improving market conditions in Texas as a particular bright spot for the company.

“Despite the absence of extreme weather this summer, ERCOT fundamentals remain strong. ERCOT’s 2017 peak load of 69.5 GW was up nearly 2% over the five-year average and came in just shy of the 2016 peak,” he said.

The recently announced retirement of more than 4 GW of generating capacity in ERCOT puts further pressure on a market with already strong fundamentals, Gutierrez said. Vistra Energy on Oct. 6 announced plans to retire three aging coal-fired units in East Texas with a combined capacity of 1,880 MW, rendered obsolete by ERCOT’s record low prices. (See Vistra Energy to Close 2 More Coal Plants.)

“For summer of 2018, these new retirements and asset delays alone will put ERCOT at the lowest reserve market on record, which is suspected to be somewhere between 10 and 11%,” Gutierrez said. “Other changes, such as delayed new builds and new industrial demand, could lower these numbers even further.”

But while the retirements are nudging up forward markets, prices are still below what is needed to justify new builds, he pointed out.

Calls to Action on Market Reform

In response to an analyst question about whether NRG would consider selling parts of its Texas portfolio, Gutierriez said, “Right now we’re very comfortable with our Texas portfolio.” He said the capability of NRG’s generation fleet aligns well with its retail loads.

But while the recent retirements are improving market health, ERCOT must do more to strengthen markets and should recognize the locational value of power plants, he said.

“Reliability and resiliency are important attributes to the grid, and we will continue to work with ERCOT to ensure that generators close to load centers are compensated for all the benefits they provide.”

Beyond the positive developments in ERCOT, Gutierrez said NRG sees several other “calls to action” occurring for market reform.

“As the power grid continues to undergo significant change — low gas prices, renewable penetration and attempts for out-of-market subsidies for uneconomic generation — regulatory bodies and other stakeholders are taking note,” Gutierrez said. “These have led to several significant catalysts, from the [Department of Energy] staff report on competitive markets and [Notice of Proposed Rulemaking], to PJM’s proposed market reforms. I cannot recall another time when there has been such urgency and reach across ISOs to improve competitive energy markets.” (See Market Summit Tackles Ongoing PJM Changes.)

Gutierrez said NRG has been optimistic about market developments in PJM, especially around the introduction of Capacity Performance.

Asked to rank the most promising areas for growth, Gutierrez responded that NRG aims to balance its generation and retail businesses and is focused on perfecting an integrated platform.

“A lot of the generation is going to be driven by our retail needs and how we grow retail, and a lot of our retail will be driven by where we have generation,” he said. “We’re still long in generation in PJM. We have a ways to go before we have a balanced portfolio like we have in Texas. … Just in terms of market structure, I would put PJM No. 1, New England No. 2 and New York No. 3.”

November 5, 2017

Eversource Q3 Earnings Flat on Mild Weather

By Michael Kuser

Eversource Energy last week reported third-quarter earnings of $260.4 million ($0.82/share), down nearly 2% from the same quarter in 2016. Earnings for the first nine months of 2017 were $750.6 million, up 5% from earnings of $713.1 million in the same period last year.

earnings Eversource Energy q3 weather — Lembo | *Eversource*

“The primary drivers of our [quarterly] results were higher electric transmission earnings being offset by lower electric distribution results,” Eversource CFO Phil Lembo told analysts in a Nov. 2 conference call.

A higher rate base boosted transmission earnings by 10.7% to $99 million, the result of the company investing $600 million in its transmission system this year through September, with just less than $1 billion planned for the full year, Lembo said.

He attributed a 7.4% drop in earnings for the company’s electric distribution and generation division to lower sales reflecting mild weather in July and August. Cooling degree days in Boston were down nearly 34% for the quarter compared with last summer and 8% below normal, he noted.

In addition to lower electric revenues, the company recorded higher property tax, depreciation and interest expense in the quarter, but was able to offset much of the negative impact by controlling costs, Lembo said. Eversource’s natural gas distribution segment posted a net loss of $6.2 million in the third quarter and earnings of $49.1 million in the first nine months of 2017, compared with a net loss of $7 million in the third quarter of 2016 and earnings of $51.9 million in the first nine months of 2016.

“For the long term, we continue to project 5 to 7% [earnings per share] growth,” Lembo said. “We are pleased with our results today and remain comfortable with our 2017 guidance, although I’d like to see some very cold weather in November and December, and that would really help us reach the higher end of our earnings range for ’17.”

Future Developments

Lembo noted that Eversource last month filed with the New Hampshire Public Utilities Commission to sell its remaining 1,200 MW of generation assets in the state for $258 million, and expects the two sales to be completed late this year or in early 2018. On the company’s proposed merger of subsidiaries NSTAR Electric and Western Massachusetts Electric Co., he said state regulators should issue a decision by Nov. 30 on the merger and grid modernization, and a decision on performance-based rate design by Dec. 29, with rates to become effective in January 2018.

Lee Olivier, Eversource executive vice president for business development, said the company’s Northern Pass transmission project achieved an important milestone Nov. 1 when utility subsidiary Public Service Company of New Hampshire filed a settlement agreement on the lease terms for most of the 192-mile route for the line.

“The settlement was reached with New Hampshire PUC staff and the Office of Consumer Advocate, the two principal intervenors in the case,” Olivier said. “We expect the New Hampshire PUC approval of the settlement by the end of the year. Taken together, we are very pleased with our current position in the siting process, with significant progress being made in all venues.”

Eversource has also partnered with Ørsted, formerly DONG Energy, to form Bay State Wind for the offshore wind solicitation in Massachusetts.

“We are preparing our bid into the Massachusetts offshore wind [request for proposals], which is due Dec. 20,” Olivier said. “Given the vast experience of Ørsted in European offshore wind and our knowledge of New England markets and transmission, we believe we will be able to submit a highly compelling set of proposals for review by the evaluators.”

November 5, 2017

MISO Planning Reserve Margin Climbs to 17% for 2018/19

By Amanda Durish Cook

MISO predicts the 2018/19 planning year will require a reserve margin just more than 17%, a figure that’s been steadily increasing over the years.

Based on its annual loss-of-load-expectation (LOLE) analysis, MISO expects the planning period to require a 17.1% reserve margin for installed capacity (ICAP) and 8.4% margin for unforced capacity (UCAP), the latter of which represents ICAP minus forced outage rates. The RTO will use the margins along with the latest load forecasts to create its enforceable planning reserve margin requirement before April’s capacity auction.

MISO LMP EIM governing body Synchronized Reserves — | *MISO*

Systemwide, MISO predicts it has about 150 GW of ICAP and almost 139 GW of UCAP to meet a nearly 126 GW expected peak demand for the June 2018-May 2019 period. The RTO’s planning reserve margin assumes the inclusion of 4,764 MW of firm UCAP and 2,331 MW non-firm UCAP from external resources.

MISO’s needed reserve margin has been on the rise since 2013. Last year, MISO predicted 15.8% for ICAP and 7.8% UCAP reserve margin for the 2017/18 planning year, up from 2016/17’s 15.2% and 7.6% values. (See MISO 2017/18 Planning Reserve Margin at Nearly 16%.) All local requirements increased from the 2017/18 planning year, the RTO noted.

Speaking during a Nov. 2 Reliability Subcommittee conference call, MISO senior engineer William Buchanan said the increase is primarily driven by an upswing in generation outages and a change in the dispatch model for demand resources, but it was partially offset by reduction in anticipated load growth. The RTO this year added a new modeling step to capture economic load uncertainty that increases the risk associated with high peak loads, also boosting the reserve margins.

Despite the yearly increases, MISO predicts reserve margins will begin to plateau. According to the LOLE analysis, they will largely hold steady because of similar forecasts over the next decade even as peak demand exceeds 129 GW by the 2023/24 planning year. The LOLE analysis found that through 2027, MISO’s ICAP reserve margin will fluctuate between 17.1 and 17.2% while the UCAP reserve margin will oscillate between 8.3 and 8.4%.

November 5, 2017

Con Edison Q3 Earnings Fall 8%

Consolidated Edison’s third-quarter earnings fell 8% to $457 million ($1.48/share), a drop the company attributed to changes in its rate plan and regulatory charges, as well as the impact of weather on steam revenues. The new rate plan includes changes in the timing of recognition of annual revenues between quarters.

earnings Con Ed Consolidated Edison Q3 — Con Edison Forecasted Average Rate Base Balances ($ in millions) | *ConEd*

“This is an exciting time in the energy industry,” CEO John McAvoy said during a Nov. 2 earnings call. “We’re incorporating renewables into the grid at an increasing rate, we’re using data analytics to provide customers with more information about the way they’re using energy and how they can save, and we’re working on programs to increase electric vehicle use and access to charging stations. At the same time, our $1 billion storm hardening program after Superstorm Sandy has made our system more reliable than ever five years later, having already prevented 250,000 power outages due to our investments.”

The company updated its guidance on adjusted earnings per share for 2017 slightly to $4.05 to $4.15/share. The previous range was $4 to $4.15/share.

Con Ed also said it is unable to estimate the amount or range of possible costs related to an April 21 subway power outage in New York City.

earnings Con Ed — ConEd plant on the East River at 15th Street in Manhattan, New York City

After investigating the outage, the New York Public Service Commission in August issued an emergency order requiring the company to inspect electrical equipment serving the Metropolitan Transportation Authority’s system, analyze power supply and power quality events affecting subway signaling services, provide new monitoring and other equipment, and file monthly reports with the commission on all activities related to the subway system. The commission last month approved another order extending the subway outage oversight beyond its original 90-day limit but has not yet issued the second order.

— Michael Kuser