Page 1458 – RTO Insider

November 7, 2017

SPP Board of Directors/Members Committee Briefs: Oct. 31, 2017

LITTLE ROCK, Ark. — SPP’s Board of Directors last week approved a cleanup of Tariff language that may have put much of the RTO’s troublesome Z2 process in the rearview mirror.

SPP Board of Directors z2 task force — SPP’s October Board of Directors/Members Committee meeting in session | © *RTO Insider*

During the board and Members Committee’s quarterly meeting Oct. 31, stakeholders approved an option put forward by Kansas City Power & Light, altering a previously approved revision request (RTWG-RR244) to align with the original intent of the task force producing the revision.

The original measure passed the Markets and Operations Policy Committee earlier in October with minimal discussion and only two abstaining votes. One of those was cast by KCP&L’s Denise Buffington, who chaired the task force that worked to simplify Attachment Z2 of SPP’s Tariff, in which financial credits and obligations are assigned for sponsored transmission upgrades.

In July, MOPC and the board accepted the Z2 Task Force’s recommendations to eliminate credits for non-capacity upgrades, such as substation facilities, and for short-term transmission service of less than a year. (See “Z2, Two Other Task Forces Expire,” SPP Board of Directors/Members Committee Briefs: July 25, 2017.)

However, the Regional Tariff Working Group’s language in RR241 would have cut off those credits for existing service agreements upon the effective date of the Tariff revision, rather than let them expire when the service did.

Buffington said the first time she realized there was an issue with the Tariff language was during the MOPC meeting, and she offered two options to correct the oversight. “Option 1” ensured that short-term firm and non-firm point-to-point transmission service granted prior to the effective date would “continue to be used to pay revenue credits … for the duration of term of that service.”

“I don’t believe the RTWG implemented the intent of the task force,” Buffington said. “We specifically talked about short-term reservations and when credits would end. Our intent was that if reservations were granted, they would continue to receive credits for the life of that service.”

Asked how the RTWG’s language had slipped by unnoticed, Oklahoma Gas & Electric’s Greg McAuley told the board and committee, “It was a matter of not enough of this discussion taking place, or not enough time when this came about.”

SPP’s Charles Locke said the task force’s proposed language was “administratively more difficult.”

“Staff does have a preference for the MOPC recommendation, because it can be implemented sooner,” Locke said. “It reduces the risk resettlements will happen. Short-term credit flows create uncertainty. Not only are there additional administrative challenges for staff, but also settlements and for member companies.”

“I hear there is some risk today,” Buffington countered, “but I don’t hear concrete reasons you can’t implement one of these options.”

“There’s an argument to be made that this is retroactive ratemaking,” said NextEra Energy Resources’ Aundrea Williams, referring to the potential premature end to transmission service agreements.

SPP FERC SPP Board of Directors PJM Insider — NextEra Energy Resources’ Aundrea Williams | © *RTO Insider*

Locke eventually offered that all three options before the board would fulfill the Z2 task force’s recommendation.

“All three could also be filed at FERC and accepted, because they’re prospective in nature,” he said. “In terms of Option 1, it’s essentially a staggered implementation. Assuming a Feb. 1 implementation date, [short-term] reservations would run for various periods of times. Eleven months might run into the fall of 2018.”

“We’ve done a lot of work here, and good things, with reaching an agreement on non-capacity upgrades,” said MOPC Chair Paul Malone, who also served on the Z2 task force. He reminded stakeholders that non-firm service only accounts for about 2% of the credits.

“Let’s do the right thing here and avoid potential trips at FERC,” Malone said. “Let’s not have this one be where a filing gets thrown back in our face.”

In the end, the board accepted the Members Committee’s unanimous approval of KCP&L’s first option.

“There’s been a lot of discussion about the potential for a burdensome administrative effort to do this,” Buffington said. “But now, we’re hearing that maybe it’s not so difficult.”

SPP to Seek FERC Input on Behind-the-Meter Load

With members unable to reach agreement on how to report behind-the-meter network load, the board directed staff to reach out to FERC for clarity, in the hopes of settling the matter during SPP’s January membership meetings.

The RTWG ended several years of work in early October when it presented new Tariff language to the MOPC. The measure would have established a 1-MW threshold for BTM output at a discrete delivery point and in front of the retail customer’s meter, but it drew only 54.6% of votes in favor. (See “Stakeholders Unable to Reach Consensus on Network Load,” SPP Markets and Operations Policy Committee Briefs.)

Southwestern Public Service appealed the rejection to the board, saying “consistent reporting of network load among all entities … is critical to ensuring that the costs of network service are fairly distributed to SPP network service customers.”

SPS said without the consistent reporting, some SPP customers would be subsidizing network service used by other customers.

“This issue has been circling the airport for the last four years. We feel like it’s time we resolve this issue,” said SPS President David Hudson. The company has been following FERC Order 890 in reporting all BTM load, he said.

“What we’re finding out is more and more people are not reporting these loads,” Hudson said. “We want consistency that everyone is receiving the same billing determinants.”

“Order 890 is relevant, but subsequent orders that directly and indirectly addressed this order said that some exclusions are relevant and can be made,” McAuley, making it clear he is not a lawyer, said in responding to the concerns of SPS and others. OG&E makes that exclusion and does not report BTM load.

“The overarching idea is that if a generator does not impact the transmission system, it should not be included for calculating that load,” McAuley said.

“People are admitting they’re inconsistent,” said Bill Grant, SPS regional vice president of regulatory and strategic planning. “It’s been four years. When are we going to make a decision?”

Board Chair Jim Eckelberger brought the discussion to a close when he asked staff to gather definitions from FERC to gain a better understanding of the problem. General Counsel Paul Suskie said staff are already working to lay out the commission’s explanations of what is and what isn’t net metering.

“Let’s make sure that at the January MOPC we have an answer we can work with,” Eckelberger said. “Let’s ensure everyone understands what the rule is.”

Director Larry Altenbaumer added that the board should make “an absolute commitment … to take action in January.”

That seemed to satisfy the members. Said Westar Energy’s Kelly Harrison: “We may not like it, but at least they make a decision.”

Brown Looks Back to Move Forward

SPP CEO Nick Brown told the board and committee that in drafting a speech for a member company’s annual meeting, he looked back at 2007 and future predictions for the industry.

“Quite clearly” no one would have predicted what has come to pass since, he said.

“We passed the 10-year view for wind energy in a year and a half,” Brown said. “Transmission expansion we got horribly wrong. Gas prices were horribly wrong. Even in the most perverse, extreme scenario, no one would have contemplated the natural gas prices we’re seeing today.”

Brown recalled gas prices were at $7/MMBtu, peaking above $13, and then settling into the $2 to $3 range.

“None of us saw that coming,” he said.

Nor did the RTO anticipate investing $10 billion in transmission within the footprint, consolidating its various balancing authorities into one, or the advent of financial transmission rights.

Still, Brown said, “I would argue we’ve been pretty strategic in what we’ve accomplished.”

Brown took advantage of the opportunity to let the board and stakeholders know he had ordered each director and committee representative copies of Craig Roach’s recently released book, “Simply Electrifying: The Technology that Transformed the World, from Benjamin Franklin to Elon Musk.”

Roach is a nationally recognized expert on electricity, and the founder and president of electricity consulting firm Boston Pacific. Last year it joined Bates White’s energy practice, for which Roach collaborated on SPP’s annual forward-looking report.

Brown also noted that SPP will on Dec. 19 mark 20 years as a reliability coordinator within its footprint. The RTO plans to celebrate the milestone on or around that date.

Finance Committee Proposing 1-Cent Increase in Admin Fee

Altenbaumer, chair of the Finance Committee, said he will be proposing a 1-cent increase in the system administrative fee at December’s board meeting, when SPP’s budget is typically voted on.

The director said the committee has suggested an increase to 42.9 cents/kWh, up from the current 41.9 cents, because of a systemwide loss of load and SPP’s commitment to absorb former staffers of the soon-to-be-dissolved SPP Regional Entity (RE), he said.

Altenbaumer also said the committee is taking advantage of Mountain West Transmission Group’s integration to possibly restructure the manner in which SPP is paid for its expenses. Any changes would be coordinated with the integration process, he said.

Directors, Members Committee, RE Trustee Elections

The board re-elected three directors and elected six Members Committee representatives to three-year terms, beginning Jan. 1, during the annual meeting of members.

Elected to new board terms were Altenbaumer, Joshua W. Martin III and Bruce Scherr. Martin has served on the board since 2003, Altenbaumer since 2005 and Scherr since 2016.

Arkansas Electric Cooperative’s Duane Highley, SPS’ Hudson, Oklahoma Municipal Power Authority’s David Osburn and NextEra’s Williams were all re-elected to the committee. Elected for the first time to the committee were McAuley and Omaha Public Power District’s (OPPD) Joe Lang.

Lang replaces OPPD’s Jon Hansen, who is retiring after 34 years in the industry.

Gerry Burrows was re-elected to the RE’s board of trustees. The RE will be dissolved by December 2018.

Revision Request to Address Potential Gaming Passes

The board approved a measure targeting potential gaming related to the regulation deployment adjustment settlements charge type. MWG-RR243 eliminates market participants’ ability to use energy offers to game incentive payments by using the lesser of the as-dispatched energy offer curve and mitigated energy offer curve for the regulation-up adjustment, and the greater of the as-dispatched offer curve and mitigated energy offer curve for the regulation-down adjustment.

Dogwood Energy’s Rob Janssen, who abstained during the MOPC’s vote two weeks earlier, said he intended to vote for the change, as it was a “good enough answer” to a “problem in need of a solution.”

Addressing member concerns about the measure’s $119,220 implementation cost and suggestions that the Market Monitoring Unit simply monitor the potential gaming, MMU Executive Director Keith Collins noted manipulation of regulation-down offers has cost the market about $1 million in recent years.

“If only it were that simple,” Collins said. “What can happen at times is there’s usually a dialogue, there’s an observation… Is this potentially an issue, or is it not? That cost can outweigh the concerns we’re having here of the implementation costs or an inefficient solution.”

Westar was the only member to oppose RR243, while two others abstained.

The board’s consent agenda included three additional RRs:

MWG-RR231: Removes locally committed resources from economic mitigation tests and creates a 10% cap for resources committed for local reliability. Addresses the practice among some resources of “self-mitigating” to pass the conduct threshold test and avoid possible mitigation by submitting competitive energy offers 10% above the mitigated offer.
ORWG-RR240: Removes Section 7 of the SPP Operating Criteria and creates a standalone SPP Reserve Sharing Group Operating Process for BAL-002-2’s annual maintenance process, which becomes effective Jan. 1.
RTWG-RR238: Addresses the financial exposure to SPP and its market participants stemming from a defaulting transmission customer avoiding responsibility for the full amount owed for the full term of a service agreement. The change also restricts the ability of SPP, transmission owners and transmission customers from recovering attorney’s fees related to performance of a service agreement, and clarifies that each party to an arbitration under the Tariff is responsible for its own fees.

— Tom Kleckner

November 7, 2017May 15, 2025

PJM Stakeholders Look to Slow Capacity Redesign Process

By Rory D. Sweeney

VALLEY FORGE, Pa. — PJM and its Independent Market Monitor provided updates to their capacity market redesign proposals at last week’s meeting of the Capacity Construct/Public Policy Senior Task Force (CCPPSTF), but the discussion was dominated by the question of when the group should recommend any rule changes.

Proponents for load — including American Municipal Power, Old Dominion Electric Cooperative, the PJM Industrial Customer Coalition (ICC) and the PJM Public Power Coalition (PPC), the Organization of PJM States and the Consumer Advocates of the PJM States (CAPS) — argued that the decision should be delayed until after FERC responds to the Department of Energy’s Notice of Proposed Rulemaking for coal and nuclear price supports. The commission has said it expects to take some action on the proposal within 60 days after its Oct. 10 publication in the Federal Register.

PJM REV Capacity Performance Market Monitor

Bowring | © RTO Insider

Generators urged staying on the task force’s current timeline of having a proposal selected to file with FERC by the end of the year. “By putting things off, we just slow down the process,” Calpine’s David “Scarp” Scarpignato said.

Johnson | © RTO Insider

Monitor Joe Bowring called for stakeholders to take the lead on how FERC responds to the NOPR.

“What you say does affect the process,” he said. “I would urge you all not to think of yourselves as passive consumers of what FERC is doing. They’re looking for guidance as well.”

Load representatives, however, said they didn’t have enough information to make an informed choice.

Ford | © RTO Insider

“Boy, I don’t have anything among any of these proposals that I can say, ‘This is what’s going to be best for the market and my customers’ future,’” said Carl Johnson, who represents the PPC.

Joe DeLosa, of the Delaware Public Service Commission, said there has been some difficulty in evaluating proposals. “We feel the time is not appropriate to move forward with proposals,” he said.

Schreim | © RTO Insider

Morris Schreim, of the Maryland Public Service Commission, asked about a commitment he said PJM made to perform an analysis of the most popular proposals. At a meeting in August, staff agreed to research possible solutions to several stakeholder concerns, including a request from ODEC’s Adrien Ford to substitute data from recent Base Residual Auctions into PJM’s model of the proposals. (See PJM Stakeholders Begin Defining Capacity Design Needs.)

Keech | © RTO Insider

PJM’s Adam Keech responded to Schreim that he remembers another meeting where staff “pretty clearly” said they would not be performing modeling.

RTO officials acknowledged the concerns of load but remained focused on the current timeline.

“I believe it’s important for this group to keep working forward,” PJM’s Suzanne Daugherty said.

PJM Revises Reference Price

PJM revised the reference price in its proposal for undefined subsidies. Previously, it was calculated using a formula for a competitive offer: the net cost of new entry multiplied by the expected average balancing ratio for the delivery year. The RTO has revised it to a “capacity repricing value” that is based on resource type and whether it’s new or existing. That value is used to resort the generation offers in the second, price-setting stage of PJM’s proposal.

Brown | © RTO Insider

The RTO presented its methodology for calculating the default values along with example values for delivery year 2021/22 measured in gross dollars. An existing combined cycle gas turbine’s value would be $84 per ICAP MW-day, while a new unit would be $501. Onshore wind would be $65 and $998, respectively.

“What we’re trying to do is determine what the market price should be for that year,” PJM’s Rich Brown explained.

Stakeholders asked Brown to provide a comparison of how reference prices change under PJM’s previous proposal and the new “capacity repricing values.”

Bowring didn’t need any comparisons.

“This is entirely inconsistent with the Capacity Performance paradigm,” he said.

IMM Revisions

The Monitor revised its proposal to expand one of the exemptions to its extended minimum offer price rule (MOPR) proposal. The renewable portfolio standard exemption would be extended to all competitive, non-discriminatory, state-mandated programs and not just competitive auctions. The IMM is also planning to adjust its public power exemption to allow supply to be “slightly” greater than 105% of demand for a year “to recognize that investment can be lumpy,” Bowring said.

Bruce | © RTO Insider

Several load proponents, including Ford, AMP’s Steve Lieberman and Susan Bruce, representing the PJM ICC, thanked Bowring for his willingness to adjust his proposal.

“We don’t think repricing is the right answer,” Ford said, acknowledging that ODEC’s proposal, which has been retracted, included repricing. “We’re really appreciative, Joe, that you’re listening to some of the concerns expressed here in the CCPPSTF and finding ways to modify what we think is a fairly pure market proposal as opposed to an administrative, two-stage approach.”

“Certainly, we continue to believe that the time is not appropriate to move forward, especially with the NOPR out there, but we appreciate the efforts that have been made to try to frame the issue,” Bruce said. “I am not at all suggesting that the time is never. … We live in a time of more uncertainty than I’ve seen. … We’re going to see some guidance from FERC soon, and I think that is going to be an important touchstone.”

Poulos | © RTO Insider

Greg Poulos, the executive director of CAPS, said some state advocates are questioning why stakeholders are “all of a sudden” focused on revising the capacity market after nuclear units in one PJM state — Illinois — received price support, particularly when they believe there will not be any new subsidies for generators. He said there is “growing support” among the advocates for the Monitor’s revisions.

“It’s definitely getting more favor from the advocate groups,” he said.

The remaining proposals — from NRG Energy, LS Power, Exelon, AMP, Northern Virginia Electric Cooperative and the Natural Resources Defense Council’s Sustainable FERC Project — had no new revisions.

Poulos expressed advocates’ concerns about “gaming” the repricing structures, and asked representatives from LS and NRG, who have also submitted repricing proposals, whether they have examined how their proposals prevent gaming and how their protections compare to other repricing proposals. The representatives said they have not noticed or been alerted to any concerns.

“We don’t see a meaningful distinction between all the repricing proposals,” Bowring said. “We think they’re all subject to the kinds of issues that were raised by [Poulos].”

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

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