Page 1124 – RTO Insider

July 31, 2018

NextEra to Close Duane Arnold Nuclear Plant

NextEra Energy Resources last week announced that it will close the 615-MW Duane Arnold Energy Center, Iowa’s only nuclear power plant, five years earlier than expected as a result of a buyout agreement with Alliant Energy.

Florida-based NextEra said that Alliant, the plant’s largest customer, will pay $110 million to NextEra in September 2020 to cover the last five years of their power purchase agreement. Alliant will instead buy 340 MW of power from four wind farms that NextEra plans spend $250 million to repower, part of a $650 million package of investments in Iowa renewables.

The deal is contingent upon Alliant getting approval from the Iowa Utilities Board to recover the buyout payment from ratepayers. Alliant said the deal will save its customers nearly $300 million over 21 years beginning in 2021.

NextEra Energy Duane Arnold Nuclear Plant — NextEra plans to close the Duane Arnold Energy Center in 2020. | *NextEra*

“Partially replacing energy from Duane Arnold with NextEra’s additional wind investments in Iowa will bring significant economic benefits to our customers,” Alliant CEO Patricia Kempling said in a statement.

NextEra said it expects to gradually reduce staff at the plant, which employs 500 now, over the next seven years as it decommissions it. It also said it is evaluating redevelopment opportunities for the plant site, including new solar energy, battery storage or natural gas facilities.

Duane Arnold is one of numerous nuclear power plants experiencing economic difficulties because of cheap natural gas and falling renewable generation costs. Bloomberg New Energy Finance Analyst Nicholas Steckler said in May that 24 of the 66 nuclear plants operating in the U.S. were either scheduled to close or wouldn’t make money through 2021.

— Peter Key

July 31, 2018November 30, 2023

FERC OKs GridLiance West Incentives, Questions ROE

By Robert Mullin

FERC last week granted GridLiance West incentive rate treatments for upgrades to a Nevada transmission line that connects to the CAISO grid, but it also ordered that the project’s overall 10.6% return on equity be subject to settlement judge procedures (ER18-1693).

The commission approved full recovery of GridLiance’s “prudently incurred” costs for its investment in upgrading the 14-mile, 230-kV Bob-Mead line if the project is abandoned for reasons outside the company’s control, as well as a 100% full “construction work in progress” incentive. FERC also granted the company a 50-basis-point “transco” adder made available to independent transmission developers.

GridLiance last year acquired Valley Electric Association’s 230-kV network in a deal valued at about $200 million, providing the company with 164 miles of transmission between CAISO and the interior West. (See GridLiance Gets OK to Acquire Valley Electric Tx Assets.)

The Six Cities group of Southern California public utilities protested inclusion of the adder, contending GridLiance had requested it just four months after reaching a settlement allowing for an overall 10.1% overall ROE, which included a 50-basis-point RTO participation adder.

Six Cities argued there was “overlapping justification” for the company’s prior request for a regulatory asset incentive (coupled with the RTO adder) and its current request for the transco adder because the latter “is designed to recognize the business model-related benefits provided by independent transmission companies,” similar to the rationale for the regulatory asset incentive already granted to GridLiance, the commission noted in its order.

But the commission rebuffed that contention, saying the functions of the transco adder and the regulatory asset incentive differ, and that it was “not persuaded that they rely upon overlapping justifications.”

“As an independent transco, GridLiance West satisfies the requirements for the transco adder. In contrast, the commission granted GridLiance West the regulatory asset incentive based upon a determination that GridLiance West had demonstrated that its request for that incentive satisfied the nexus test established in Order No. 679,” the commission said.

FERC also rejected as beyond the scope of the proceeding Six Cities’ request that GridLiance be ordered to disclose all authorized incentive adders in future transmission development proposals to CAISO because the adders could have a “material impact” on transmission projects in the ISO.

But while the commission favored GridLiance’s request for the adders, it also said its preliminary analysis indicated the overall 10.6% ROE for the Bob-Mead project might be too generous.

“Based on the record in this proceeding, the commission does not have a basis for determining whether GridLiance West’s overall ROE, inclusive of the transco adder granted above, falls within the zone of reasonableness,” FERC said in ordering settlement procedures.

July 31, 2018

MISO Informational Forum Briefs: July 24, 2018

MISO issued two maximum generation alerts and conservative operations declarations because of severe weather in June and a heatwave in July.

Both months were hotter than normal, and MISO recommended suspending transmission and generation maintenance in the North and Central portions of its Midwest region on July 5, when temperatures and loads were both above forecasts. The RTO said its system was stable throughout the event.

MISO spokesperson Mark Brown said staff coordinated closely with members and neighboring system operators during the event to manage generation and transmission resources. “MISO and our members train regularly and intensively to manage the power system in all types of conditions,” Brown told RTO Insider, adding that the alerts are meant to provide “situational awareness” to members.

The RTO also declared a hot weather alert for MISO South July 20-23 when the average temperature was 99 degrees Fahrenheit.

miso maximum generation alert severe weather — Rob Benbow | © *RTO Insider*

MISO Senior Director of Systemwide Operations Rob Benbow also said the system performed well during June despite above-normal temperatures and severe weather in the South region.

“We did see some hot weather alerts in the Central and North regions … at the middle to the end of the month, and we also experienced a transmission system emergency due to a forced outage in the South region in the early part of June, and that was followed by conservative ops and a max gen alert on the following day until that facility was returned to service,” Benbow said during a July 24 Informational Forum.

The day after severe weather on June 3, MISO declared a transmission system emergency in South with a maximum generation alert and conservative operations instructions. Benbow said the event caused real-time price spikes.

MISO’s June load peaked at 121 GW on June 29, up about 10 GW from last June’s peak. Average load was just under 77 GW, up 7 GW from a year earlier. Average real-time energy prices were $31.74/MWh, up 13%, which MISO attributed to localized congestion and higher demand.

MISO Reviewing Hartburg-Sabine Proposals

MISO has received multiple proposals for its second competitively bid transmission project, but it will not reveal the number of companies behind the proposals for at least another month — if at all.

The second request for proposals for the Hartburg-Sabine 500-kV junction project closed July 20, part of MISO’s 2017 Transmission Expansion Plan. The project will be in service by 2023 and is meant to alleviate system congestion in eastern Texas. The RTO opened the submittal window in early February.

However, MISO only identifies the number of proposals and their submitters once they’ve been judged and accepted as complete during an initial review expected to wrap up in early September, CEO John Bear said. The RTO will then post a list of finalists advancing to the evaluation process. Incomplete proposals are not revealed.

“MISO is pleased with the robust number of responses to the request for proposals,” Aubrey Johnson, executive director of competitive transmission, said in a statement. “This shows broad interest from qualified transmission developers and underscores the confidence in our competitive selection process. We look forward to moving to the next phase of the selection process to identify the best proposal for this important project.”

MISO plans to announce its selected developer for the project by Dec. 31. Bear said the project is expected to cost $129 million and have a benefit-to-cost ratio of 1.35:1. He added that it is the RTO’s first competitive project to include a substation.

— Amanda Durish Cook

July 31, 2018January 31, 2024

Overheard at Infocast’s SPP and MISO Markets Summit

KANSAS CITY — Infocast’s first SPP and MISO Markets Summit last week faced tough competition at its hotel, which was also hosting the U.S. women’s national soccer team, the Detroit Tigers, Journey and Def Leppard.

Still, the July 24-26 conference attracted participants and industry representatives from the RTOs’ footprints for panel discussions on resource mix, gas builds for reliability, competitive wind pricing, unlocking solar energy’s potential, demand response and energy efficiency initiatives, and the future of the Western grid.

Much of the focus was on the RTOs’ interconnection queues, which have ballooned in recent years as renewable developers chase expiring federal tax credits.

Renewable projects account for 78 GW of the almost 90 GW in MISO’s queue, and about 74 GW of the 77 GW in SPP’s queue. Neither RTO has a coal project on the books.

MISO and SPP are used to the growth of wind power, which supplies about 17-18 GW of energy for both RTOs. But the explosion of solar and battery projects (36 GW in MISO, 20 GW in SPP) has come as a surprise.

Vikram Godbole, MISO’s director of resource utilization, said solar projects now outnumber wind projects in a queue with an “historic” amount of generation. He said the generation is almost 7 GW higher than the “most extreme” staff forecasts of a year ago.

“I never thought that would happen,” Godbole said. “At what point does it end, I don’t know. We’ll continue to see a rise in solar the next few years, especially as the projects with wind [production tax credits] drop out.”

“The reason you’re seeing solar is because of the tax credits,” said Ameren’s Jeff Dodd. “That’s not a shock.”

“It’s mind-boggling when you look at it,” said Steve Purdy, SPP’s manager of generator interconnection. He compared the queue with the RTO’s summer peak load of 50 GW, saying, “You can see the challenge we have in squeezing that enormous amount of generation into a relatively small amount of load.

“That’s led to areas where we don’t have enough load to absorb all the requests,” Purdy said. “We’ve resorted to creative engineering and engaged our stakeholder group to help with those challenges, both in technical issues and the process issues.”

SPP stakeholders in April approved an overhaul of the generator interconnection process, leading to a simpler three-stage process that mimics MISO’s. (See “Members Approve Three-Stage Process for GI Requests,” SPP Markets and Operations Policy Committee Briefs.)

The grid operators say they hope recent changes to the GI process will help them work through the backlog of requests and weed out developers trying to manipulate the process. Godbole said MISO is just now processing 2016 February and August cycles.

“A lot of GI customers are getting anxious about being able to start construction on time,” Godbole said. “They need some idea of whether they’ll get a [GI agreement] before the summer of 2019.”

“It’s going to be very difficult for anything in the 2017 cycle to get a GIA in time, just based on the cycles,” Dodd said.

The simpler, three-stage study processes include heftier security deposits at each stage. That helps ensure only the most serious developers are involved, as studies have to be redone when a project is withdrawn.

“The interconnection process is becoming the long-delaying issue in the development cycle. We have to put more thought into how we enter these queues as a customer,” said Tradewind Energy’s Derek Sunderman. “We’re trying to stay ahead of those changes so that we can continue to have a pipeline of projects. Security deposits … have become the No. 1 driver on the budget side of this business.”

Sunderman said the changes seem to indicate the three-stage study process “is moving forward.” He said a Tradewind analysis of MISO’s recent study results showed fewer customers dropped out at the later stages, an indication of the more favorable results they were getting for their projects.

“That tells us the interconnection customers are becoming very educated,” Sunderman said. “The problem is the study length. It’s just not working as fast as we would like.”

Western Grid Hears the Markets Call

David Kelley, director of seams and market design for SPP, said improved renewable technology is not only evident within RTOs, but in the efforts to create markets and new services in the Western Interconnection.

“Many of the states and utilities are looking at integrating more renewables,” he said during a panel on Western grid regionalization. “RTOs and markets are very capable of providing the type of environment and economies of scale that facilitate that type of development. It’s hard to argue against how broader regions plan the system than individual companies doing it on their own.”

Kelley noted SPP had 3 GW of wind energy on its system in 2008. “Now, it’s 17 gigs,” he said. “Our robust transmission planning system helped do that.”

“The biggest hurdle of getting renewables to the market is the tariff’s ways [through pancaked rates] it takes to get the power to a load-serving entity,” said Swaraj Jammalamadaka, a former MISO staffer, now director of transmission for Apex Clean Energy. “MISO, SPP, PJM … they are definitely a benefit for integrating low-cost generation in the system.”

Markets also provide transparency into price, costs and benefits, said Kelley and Pat McGarry, managing director of The Energy Authority.

“The transparency is real in RTO markets,” McGarry said. “It can cause issues, because now, everybody can see what the prices are. If you self-commit a generating unit when the prices are low, it’s, ‘Why are you running?’”

“For us, the biggest struggle is the market no longer depends upon fixed [power purchase agreements],” Jammalamadaka said. “A significant enabler in markets like SPP’s is people are able to sell their power through very intelligent financial instruments. They can only be made available if you have a liquid market.”

SPP is among those attempting to offer market services in the West, having been working to integrate the Mountain West Transmission Group, a collection of eight Rocky Mountain-area entities, since January 2017. That deal has been on life-support since Xcel Energy, which accounts for 40-50% of Mountain West load, announced in April it was withdrawing from the group. (See Xcel Leaving Mountain West; SPP Integration at Risk.)

“That certainly changes things from the cost-benefit perspective,” Kelley said. “[The remaining entities] are in a very deliberate process of calculating the benefits and costs of participating in SPP. We expect that process to take place over the next few weeks before they make a final decision.”

Grappling with Adding Value to Coal Resources

Without new coal-fired generation in their futures and with increasingly large amounts of renewable energy disrupting their fuel mix, how are SPP and MISO to incent new coal resources?

Casey Cathey, SPP’s manager of operations engineering analysis and support, said while the RTO is fuel agnostic, it does value flexibility. To ensure coal resources are valued, he said the grid operator is evaluating two products that may provide benefits for their generation: a multi-day economic commitment and a de-commitment enhancement.

“Coal unit parameters are too expensive for the day-ahead engine to pick up. It can cost $200,000 to start, so maybe we can disperse that cost over a period greater than 24 hours,” Cathey said. “A multiday economic commitment would be better able to assess coal and compensate it, instead of having to self-commit.”

He said a de-commitment enhancement isn’t as easy as it sounds, with day-ahead positions and financial obligations that must be accounted for.

“It will help coal in two ways. It will help to further optimize commitments instead of coal having to self-commit; it will help … maximize its revenue in the de-commitment process,” Cathey said of an action that’s up to the market participant. “It’s basically placing that decision in the hands of the RTO, which theoretically should make a little more money [for coal resources], through optimal cycling. If other resources completely de-commit, it could potentially inflate prices for those resources that stick around.”

“The real question may be how we incent the right resource characteristics,” said Laura Rauch, MISO director of resource adequacy coordination. “We commonly think of coal as the resource we know and love because of these attributes, but as Casey said, it’s about making sure we have the market signals to go and motivate people to build resources with the right characteristic. We have to have the forward projections with the states and load entities, so that we’re not just reacting, but that we’re getting the generation built to replace some of these retired units with the transmission to support it, and with the general attributes we need to keep the system reliable.”

Lincoln Electric System’s Dennis Florom, whose company owns interests in several coal plants, said there’s still a place for new coal generation, although “it’s going to be a tall order.”

“We need to look at new ways to clean it; we need to look at ways to change public perception. It’s not a resource people want to build,” he said. “As we bring in new resources such as storage, it’s actually going to have an interesting play. You’re going to see those storage resources placed in areas of high congestion … where prices are typically high. As you bring in resources that will eliminate congestion, you’re going to see a flattening of prices.

“That makes me wonder if, out in the distance, somewhere, maybe the next 10 years, we see prices flatten,” Florom said. “People will recognize that resources with higher fixed costs, but low variable costs, will be able to take advantage of those flattening prices.”

Gas Generation No Ordinary Bridge Fuel

Appearing on a panel discussing gas-fired generation’s role in grid resilience and reliability, Vectren Director of Regulatory Policy and MISO Affairs Justin Joiner asserted that gas is not a bridge fuel but, rather, “a highway.”

“[Gas units are] foundational to the adoption and use of the latest technological advances to meet load needs,” he said. “Gas is cost effective, flexible, reliable, resilient and fast ramping. Additionally, resiliency is a regional matter. How one meets its load needs in a resilient manner is a system-by-system consideration, unique to each LSE.

“If you look at the MISO queue and the amount of baseload retirements [20 GW recently, 12-20 GW forthcoming], there is a need for fast-ramping, dispatchable generation. Gas will meet that need,” Joiner said.

Scott Wright, MISO’s executive director of strategy, agreed with the critical role gas-fired generation can play. He pointed to the 10 GW of gas projects in the ISO’s queue, noting most will be used to address continued retirements of legacy resources.

“Due to its reliability and flexibility attributes, gas-fired generation will support future change,” Wright said. “Preliminary studies from our planning scenarios indicate that we’ll be calling on a comparable amount of total gas capacity in the future to provide ramping that is at least two to two-and-a-half times the amount of today’s gas ramping. This means we’ll need more capability, not less, from gas-fired generation, despite and related to the large growth expected in renewable resources.”

Natasha Henderson, who manages regulatory and market affairs for West Texas-based Golden Spread Electric Cooperative, said all generation types will continue to contribute to resilience. But given quick-start gas units’ ability to cover sudden drops in renewable energy, she said gas-fired generation should be compensated accordingly.

“At this juncture, gas generation is the most critical type of generation to meet reliability and resiliency needs, and flexible gas generation will become increasingly important as we see more and more renewables added to the system,” Henderson said. “As technology advances and the resource mix continues to change, wholesale market structures will need to not only react but proactively adjust. It’s critical that we both define the attributes of reliability and resiliency and ensure that markets properly compensate these attributes to incent the correct future generation mix.”

MISO, SPP Improving the Interregional Process

Cathey also engaged Jeremiah Doner, MISO’s director of seams coordination and membership services, in a friendly discussion over improvements to the interregional planning process and January’s “Big Chill.”

Having failed to agree on a single interregional project so far, the two grid operators are working to reduce hurdles, such as building a joint model and eliminating the $5 million threshold to qualify as an interregional project. To save time, SPP and MISO will now study potential projects within their own regional models. They have also added new benefit metrics, such as the avoided cost of other projects. (See MISO, SPP Loosen Interregional Project Requirements.)

“It doesn’t take an engineering power flow model to determine projects need to be built. We have artificial human barriers … because of the model build and barriers like the $5 million threshold,” Cathey said. “There’s no reason we shouldn’t build a $4 million project if it leads to benefits. SPP stakeholders are getting a little bit tired of talking about interregional projects. We should be building transmission across the seam.

“But give MISO kudos as well. They recognize the same thing,” Cathey said.

“We’re both on board and at the table working on these problems,” Doner said.

The two also talked about the Jan. 17 severe weather event, when generation shortfalls in MISO South led to heavy north-south transfers across SPP’s system and a maximum generation alert in the region.

Cathey, a Louisiana native, noted temperatures in his home state were 30 degrees Fahrenheit lower than they should have been. Older generating units, without proper cold-weather packaging, tripped offline, costing MISO 5 GW of capacity.

“It was a challenging day,” he said. “There are a number of things that could have been done differently that day. We could have been a little more proactive. We’re discussing with [MISO and neighboring Southern Co. and the Tennessee Valley Authority] how we can learn from it and better forecast these issues.

“We practice load shedding, but we don’t practice emergency purchases, which prevents load shedding. We’re working on that with the neighboring reliability coordinators. That alone would have helped MISO,” Cathey said.

“That’s a very accurate description of what happened that day,” Doner said. “It’s important to remember we kept the lights on. MISO is very appreciative of the emergency energy we had to purchase on that morning. We’re in this together to keep the lights on. We should support each other, and we did that day.”

Wind Developers Argue for Level Playing Field

A pair of wind developers said that while technological improvements continue to improve wind energy’s competitiveness, the loss of the PTC threatens to tilt what they say is now a level playing field.

“Yes, wind energy has evolved to where it’s cost competitive,” EDP Renewables’ Rorik Peterson said when asked what harm the PTCs’ expiration would cause. “But there’s no form of electric generation that doesn’t receive some sort of federal support. If the PTCs expire, that leaves wind without any form of support. As to fairness in the marketplace aspect, I take exception to that.”

“On a level playing ground, we compete quite well,” said Apex’s Mark Mauersberger. “Having us be the only generation that doesn’t benefit from a subsidy is unfair.”

Peterson said solar energy’s increasing competitiveness, as evidenced by its growing presence in the MISO and SPP interconnection queues, “will certainly change the landscape.”

“I would expect with the phaseout of the PTCs and the loss of their full value after 2020, the tariffs on solar panels rolling off, that solar will consume a greater share of the renewables market,” he said. “I would expect to see a decline of consumption of wind after 2020, but I still expect to see wind be a viable component of the generation mix going forward.”

If so, then technology will continue to play a key role.

“One of the largest cost components of the wind project is the turbine,” said Mauersberger, whose company’s Dakota Range Wind project in South Dakota will use 72 turbines to generate 300 MW of energy. “Using [fewer] turbines shrinks the footprint, reducing the cost of cabling, roads and other civil costs. That trickles down to really reasonable pricing. We’re seeing pricing down south [in Texas and Oklahoma] in the $15/MWh range. I think that’s where we’re headed pretty quickly.”

— Tom Kleckner

July 29, 2018

New England Women Talk Climate Change, Resilience

By Michael Kuser

LOWELL, Mass. — Adapting to climate change in New England calls for building resilience into both the region’s infrastructure and its people, and women are particularly suited to help face the challenge.

So said participants at the New England Women in Energy and the Environment’s 4th annual panel discussion in the “Women Shaping the Agenda” series July 26.

NEWIEE climate change — NEWIEE panelists (left to right): Penni McLean-Conner, Eversource; Ellen Miller, Avangrid; Elizabeth Henry, ELM; Alison Brizius, City of Boston; and Katherine Kemen, Partners HeathCare. | © *RTO Insider*

Massachusetts Gov. Charlie Baker’s Executive Order No. 569 nearly two years ago called for an integrated strategy on climate change, calling it not just an environmental but a cross-government, cross-sector issue, said Katie Theoharides, assistant secretary of climate change in the state’s Executive Office of Energy and Environmental Affairs.

“You name it, this issue touches everything,” Theoharides said in her keynote appearance.

Theoharides said Massachusetts’ plan for climate change adaptation will be issued in September. Her office is also working with the state’s Emergency Management Agency to update its hazard mitigation plan, which will be folded into the climate plan.

“The state has focused on moving from standalone climate change plans and reports to incorporating those types of actions, and their funding, into the mainstream,” Theoharides said. “That effort has formed the basis for an environmental bond bill (H.4599) that is still in conference right now.

“Most of our resiliency language that we put in there will not be conferenced because it was previously agreed to by both the Senate and the House, so we’re very excited to see the executive order actually getting codified into state law.”

By coincidence, lawmakers finalized the environmental bond bill on the same night Theoharides spoke.

It’s also important to work with other states, she said, as in the “phenomenally successful” Regional Greenhouse Gas Initiative, the country’s first effort to set a cap on emissions from the power sector and reinvest carbon allowance auction proceeds into strategies to reduce energy consumption and thereby continue making gains to reduce emissions.

“We’re very focused on science and data as tools to use in governing … which has helped us deal with climate change in a nonpartisan way,” Theoharides said. “We don’t make it a blue state/red state issue.”

Follow the Money

Using the plan as a guide for the state’s spending on climate change will help build on progress made so far, as “it’s important to figure out where the money all goes,” Theoharides said.

“One of the first things I learned about in state government was how the budget process works, how procurement works,” she said, adding that her agency early on determined how to tap existing funding streams to support climate initiatives. “We’re not going to have a giant pot of money right away to do this work; we need to build that pot of money. In the interim, figuring out ways to use the existing money more strategically and to get the priorities into that funding is important.”

Elizabeth Henry, president of the Environmental League of Massachusetts, said the lack of money usually poses the biggest obstacle to implementing climate change adaptation programs, and that she was “very excited” to see the state increasing environmental funding.

“We’re also working to link carbon mitigation and climate adaptation in a really fundamental way,” Henry said. “We see this core problem of carbon as also potentially being part of the solution. So we’re advocating to put a price on carbon … and see [it] as a key part of the solution.”

Stormy Weather

Alison Brizius, director of climate and environmental planning for the city of Boston, said two years ago the city released a comprehensive plan to prepare it for the impacts of climate change, including a citywide vulnerability assessment “looking at the climate change vulnerabilities we face and the very large-scale key strategies across the sectors on how we’re going to deal with those challenges.”

Flooding and sea level rise pose the greatest threats in Boston, so Brizius and her team began to plan how to raise key infrastructure district by district and parcel by parcel. She said the city also must handle increasing temperatures and storm runoff and is working to “embed” the values of resilience in planning processes.

Penni McLean-Conner, chief customer officer and senior vice president at Eversource Energy, said her company had built the new Seafood Way Substation in South Boston last year — one of the first in the nation to build for resilience.

“It is designed to handle flooding; it’s 23 feet above sea level; it’s designed to withstand hurricanes,” McLean-Conner said. “That’s a 50-year investment. We were thinking about that investment knowing we were going in an area that needed to have resiliency.”

Another utility veteran, Ellen Miller, vice president for projects at Avangrid Networks, said the company’s regulated utilities are “looking at what we have to do to prepare for the increasing frequency and duration of storms that we’re experiencing.”

Miller highlighted the New England Clean Energy Connect project of Avangrid subsidiary Central Maine Power to deliver 1,200 MW of Canadian hydropower to Massachusetts as an example of a strong stakeholder process. She also said Avangrid had “recently announced a $2.5 billion plan to harden our system in response to climate change.”

Katherine Kemen, program manager for emergency preparedness at Partners HealthCare, said her stakeholder process involved corporate managers. Because it would be prohibitively expensive to provide backup systems for every part of a large hospital, she said she has to be realistic in choosing what solutions to propose.

“We’re in the third phase of a strategic resiliency initiative,” Kemen said. “We started with 30 critical sites across our system, including data centers and research centers, and mapped out projections … to 2030 and 2070.”

Women’s Role

Women are the most vulnerable to climate change, but in some ways, the things that make women more vulnerable also make them more poised to deal with the issue, Theoharides said.

In the U.S., climate change is projected to hit poor women the hardest of any demographic, she said.

“From what I’ve seen of women working in this field, anything from helping negotiate the Paris Agreement to really shaping the field of adaptation, 10 years ago women were at the forefront,” Theoharides said.

“I think women are really good at collaborating across disparate spaces; they’re really good at bringing cross-cutting issues together. I think we’re good at building partnerships and looking for different answers, so there’s a real role for women to play as connectors,” she said. “Listening is a key aspect of this work.”

Julie Chen, vice chancellor for research and innovation at the University of Massachusetts Lowell, which hosted the event, said women learn to be resilient from their own life experiences, whether from dealing with overt misogyny — a male client asking another man a technical question even when a woman is in charge — or microaggressions, which are tiny acts in themselves but have a decidedly negative cumulative impact on women.

Chen also promoted her university as a great research source for the women in the audience.

The school has “over 40 faculty who work in energy and environmental areas, everything from solar, wind, fuels, the grid, energy storage [and] nuclear. They do experiments; they do modeling; they have unique testing equipment that you might want to take advantage of,” Chen said.

July 29, 2018

AEP, NextEra Energy, Xcel Energy Briefs

During American Electric Power’s second-quarter earnings call with financial analysts last week, CEO Nick Akins was pressed about the uncertainty the company’s proposed Wind Catcher Energy Connection was placing on its share price. In the company’s earnings release, Akins had promised the company’s investments in its regulated businesses “will continue to support our 5 to 7% earnings growth rate.”

aep nextera energy xcel energy q2 2018 earnings — Akins | *Business Roundtable*

During the July 25 call, Akins was asked at what point do you decide that you are better off walking away from the table and the uncertainty?

“A very fair question,” he responded. “We cannot afford to continue to allow this thing to languish given construction has started and the company is incurring expenses associated with it.”

Two days later, AEP removed the uncertainty, canceling Wind Catcher, a $4.5 billion, 2-GW wind farm in the Oklahoma Panhandle. The move came one day after the Texas Public Utility Commission rejected the proposal. (See related story, AEP Cancels Wind Catcher Following Texas Rejection.)

Wall Street appeared to like the company’s reaction. After closing the day of the earnings call at $69.38, AEP stock ended the week at $71.14/share, up $1.76. That’s still well below the company’s 12-month high of $77.63, which it hit in November.

Ohio-based AEP reported a “very healthy quarter” thanks to a late winter and early summer, with second-quarter earnings of $528 million ($1.07/share). That was up from the prior year second quarter of $375 million ($0.76/share).

NextEra Energy Earnings Up

NextEra Energy announced a small increase in second-quarter earnings last week, reporting net income of $795 million ($1.64/share). That was a $2 million improvement from the prior year’s quarter of $793 million ($1.68/share).

The Florida company’s adjusted earnings of $1 billion ($2.11/share), compared to $881 million ($1.86/share) in last year’s second quarter. That beat Zacks Investment Research’s consensus estimate of $2.07/share.

NextEra announced in May it will pay Southern Co. almost $6.5 billion for Gulf Power, Florida City Gas and shares in the Oleander and Stanton natural gas power plants. CEO Jim Robo said the company “remains on track to meet its objectives for the year.”

Despite the good news, NextEra’s stock lost $2.03/share following the July 25 earnings announcement, finishing the week at $166.99.

Xcel Energy Beats Analysts’ Expectations

Xcel Energy reported a 16% increase in second-quarter earnings boosted by favorable weather and sales growth, exceeding analysts’ expectations.

The Minneapolis company on Thursday announced earnings of $265 million ($0.52/share), up from $227 million ($0.45/share) a year ago. Zacks’ analyst survey had forecasted profits of 47 cents/share.

The results exclude the effects from 2017’s federal tax legislation.

The company’s stock finished the week at $46.59/share, up 68 cents.

— Tom Kleckner

July 29, 2018

NYISO Management Committee Briefs: July 25, 2018

RENSSELAER, N.Y. — NYISO experienced a peak load of 31,293 MW on July 2, the highest demand so far this summer but falling far short of the all-time peak of 33,956 MW, the ISO’s Management Committee heard last week.

Operations Vice President Wes Yeomans on Wednesday informed the committee about grid operations during a six-day heat wave in early July, which will be reported formally in August.

High temperatures and humidity on July 1 caused the grid to have “experienced a very high peak for a Sunday,” Yeomans said.

The ISO activated demand response on July 2 in New York City’s Zone J in response to the weather and the forced outage of a 345-kV line in the city, he said. Last summer, demand never exceeded 30,000 MW, with the peak of 29,699 MW occurring July 19, coming in 7% below the 10-year average of 31,968 MW.

The 33,956-MW record came at the end of a weeklong heat wave on July 19, 2013.

The ISO in May reported a total of 42,169 MW of resources available to meet this summer’s expected peak demand of 32,904 MW, 2.9% above the 10-year average. (See NYISO Ready to Meet Summer Demand.)

COO Rick Gonzales delivered the operations report for June, noting that high levels of wind curtailment upstate were coincident with scheduled outages of the Browns Falls-Taylorville 115-kV line and the forced outage of the Marcy-Coopers Corners 345-kV line.

MC Approves Change on Congestion Data Reporting

The committee voted in favor of changing how NYISO reports historic congestion, supporting the Business Issues Committee vote earlier in July that the current process is resource-intensive and the resulting data under-utilized.

The vote recommends that the Board of Directors endorse the new process, which will require Tariff changes. (See “BIC OKs Change on Congestion Data Reporting,” NYISO Business Issues Committee Briefs: July 11, 2018.)

No Cost of Service Study

The committee voted that a new cost of service study (CSS) should not be conducted during late 2018 and 2019 to inform a decision on whether a modification of the 72%/28% cost allocation between withdrawal billing units and injection billing units is warranted, pursuant to Tariff Section 6.1.2.3.

Chris Russell, manager of customer settlements, said that language included in Rate Schedule 1 requires a vote by the committee in Q3 2018 to determine whether a new CSS should be conducted to evaluate the allocation between withdrawals and injections.

The ISO’s current RS1 allocation provides rebates for recoveries from non-physical transactions.

MC to Help Fill Board Vacancies

Committee Chair Erin Hogan said she had been asked to form a subcommittee to help fill two upcoming vacancies on the board after Directors Thomas F. Ryan Jr. and Jane Sadowsky complete their terms.

Hogan asked that each sector representative by Aug. 1 provide two candidates to serve on the subcommittee in order to complete preliminary work next month and get a search firm to select board candidates by Thanksgiving.

— Michael Kuser

July 29, 2018

CAISO Board OKs RC Rate Plan, RMR Change

By Robert Mullin

CAISO’s push to become a reliability coordinator (RC) passed its first milestone last week after its Board of Governors approved the proposed rate design for its newest line of business.

The board also passed an “interim” rule change for the ISO’s reliability-must-run program, as well as approving RMR designations for two NRG Energy gas-fired generators in the Southern California Edison service territory.

Approval of the RC rate scheme came just a week after Peak Reliability, the current RC for the Western Interconnection, announced that it would cease operations at the end of 2019. (See Peak Reliability to Wind Down Operations.) Peak made the decision to fold after most of its customer base defected to CAISO, which promised to offer similar reliability services at significantly lower cost.

caiso rmr reliability coordinator rc — CAISO Board at meeting last November. | © *RTO Insider*

“That’s compatible with our plan to stand up our own RC and offer those services to others in the West anyway,” CAISO CEO Steve Berberich told board members during their July 26 meeting. “We intend to work very closely with Peak to make sure we have a reliable transition of these services.”

Phil Pettingill, CAISO director of regional integration, told the board the ISO is “uniquely positioned” to provide RC services in the West because of its “very detailed” network model, which can be leveraged “to potentially increase reliability in at least that portion of the interconnection that we’re operating.”

“Because we already have these tools and that infrastructure in place, our projections are showing that we’ve got an opportunity to provide that RC service at roughly 40% of what the current costs are, and provide that higher quality service at the same time,” Pettingill said. The ISO estimates it will be able to provide RC services to the entire interconnection for about $18.5 million, compared with Peak’s current budget of $45 million. (See CAISO Puts $18.5 Million Price Tag on RC Services.)

CFO Ryan Seghesio told the board that CAISO based its RC rate design on the existing rate design, rather than calling out RC services as a distinct function from other ISO operations. He noted that RC services would initially represent about 2% of CAISO’s annual costs upon roll-out to the ISO’s balancing authority area on July 1, 2019, followed by an increase to 9% as others in the West join by the end of next year. The ISO plans to hold its overall revenue requirement to about $205 million, even after introducing RC services.

With the revenue requirement largely stable, Seghesio said RC revenue streams will decrease CAISO’s grid management charge rate — the ISO’s primary revenue source — by $11 million, as well as reduce rates for Western Energy Imbalance Market participants. Supplemental RC services will be billed separately, potentially further reducing other ISO charges.

Seghesio noted that some RC customers have asked the ISO to implement stronger cost containment measures in its proposal, “essentially assuring or guaranteeing some maximum level of cost increase year over year.” But CAISO management “currently believes our existing cost containment measures are adequate,” he said, pointing out that the ISO’s revenue requirement is capped by FERC.

Seghesio said the RC allocation will remain fixed at 9% at least until the ISO performs its next cost-of-service study.

“We’re very confident at this point that the 9% represents a good look at how the 2020 cost-of-service study will look, because that’s the data we’ve used” to arrive at the estimate, Seghesio said.

Speaking during public comment on the proposal, Jeff Rehfeld, senior counsel with NaturEner, expressed “disappointment” that the ISO plans to charge generation-only balancing authorities the same rates as BAs that serve load. The company is a renewable energy developer that operates two generation-only BAs in Montana.

“Our balancing authorities, due to their generation-only characteristics, do not require some of the reliability coordinator services that are required to be provided to other balancing authorities which have load and transmission. And, similarly, the amount of attention and resources that a reliability coordinator must devote to a generation-only BA” is less than required for BAs with load, Rehfeld said.

The proposed rate structure “is not defensible under a cost-causation analysis, [nor] is it fair or equitable,” he said, because it requires generation-only BAs to subsidize other RC customers. He held up Peak’s funding model as more equitable.

“In the case of gen-only and, particularly, your company, the variability of the resources and also the prospect these resources will be operating in two separate RC areas, adds a complexity that justifies our volumetric [megawatt] calculation” for determining rate, Pettingill responded. “I think it’s really the operational engineering analysis that supports our logic.”

Jim Shetler, general manager of the Balancing Authority of Northern California, said his group is “comfortable” with the Tariff changes as proposed. He also pointed to another milestone for CAISO’s RC effort: its first customer commitment.

“In keeping with the concept of early notice on what entities intend to do, I would like to report that at its meeting yesterday, the BANC commission authorized me to go forward with transitioning our services from Peak RC to the ISO, and we’ll be looking forward to making that happen,” Shetler said.

CAISO plans to file the RC rate proposal with FERC at the end of August.

RMR Actions

The Board of Governors on Thursday also approved a modification to the ISO’s RMR program that would replace the existing pro forma RMR agreement with an “interim” version of the agreement. CAISO management sought the change “pending the development of a more comprehensive proposed amended RMR agreement” targeted for board approval in March 2019.

The interim agreement contains a provision allowing for its termination and the immediate re-designation of an affected RMR unit under a “new comprehensive agreement” upon FERC approval, said Keith Johnson, CAISO infrastructure and policy manager.

Pacific Gas and Electric and the Six Cities group of publicly owned utilities in Southern California supported the proposal, while Calpine called it “piecemeal and unnecessary.”

Johnson was careful to note that the interim agreement would not apply to the two gas-fired plants the board on Thursday agreed to designate as RMR — the 54-MW Ellwood Generating Station and one unit at the 1,516-MW Ormond Beach plant. NRG announced in March that it planned to retire the plants, along with its Etiwanda Units 3 and 4. (See NRG Set to Retire California Gas Plants.)

CAISO determined that Ellwood’s retirement would leave a 45-MW deficiency in the local capacity requirement for the Santa Clara subarea next year, while the loss of Ormond Beach would result in a 170-MW shortage for the Moorpark subarea. The ISO expects the units will also be needed in 2020 while the region awaits completion of a 230-kV transmission line and SCE completes the procurement of new resources expected to be online in 2021.

Eric Eisenman, director of ISO and FERC relations for PG&E, said his company was “neutral” on the specific RMR designations but urged CAISO to more quickly address the company’s concerns about the RMR mechanism, such as the lack of a must-offer obligation for RMR units and their existing rate of return.

Eisenman acknowledged that the RMR revision process is moving along, “but not at the pace that matches the urgency PG&E has expressed and continues to express.”

“In all likelihood, if there are any new RMR designations in the PG&E footprint for 2019, PG&E will oppose the terms and conditions before this board and before FERC,” Eisenman said.

CAISO Governor Ashutosh Bhagwat noted the ISO’s expressed concerns about the difficulty of rushing through an initiative as complex as that related to RMRs.

“But I do share PG&E’s sense of urgency. I feel like the faster we can get this done, the better, because we’re essentially [placed] in the position of ad hoc negotiations every single time” the ISO negotiates an RMR, Bhagwat said. “That’s clearly not ideal.”

July 27, 2018

FERC Flooded with Comments on Pipeline Permitting

By Rich Heidorn Jr.

Environmentalists and state officials called on FERC this week to broaden its review of natural gas pipeline applications while gas producers and electric generators said only minor changes are needed to the commission’s 1999 policy statement.

FERC received about 2,000 comments in response to its Notice of Inquiry asking whether it should reconsider how it balances project benefits against adverse consequences in light of the shale gas revolution, global warming and other changes since it last considered the issue almost 20 years ago (PL18-1). (See FERC Outlines Gas Pipeline Rule Review.)

Most of the comments before Wednesday’s filing deadline came from individuals opposed to fracking and pipeline expansions.

natural gas pipelines NEPA FERC — | *National Fuel Gas*

The commission asked for comments on four topics: the reliance on precedent agreements to demonstrate project need; landowner interests and the use of eminent domain; the evaluation of alternatives and environmental effects under the Natural Gas Act and National Environmental Policy Act; and the efficiency and effectiveness of the commission’s certificate process.

Status Quo

The Edison Electric Institute, Electric Power Supply Association, American Petroleum Institute, American Gas Association and Interstate Natural Gas Association of America (INGAA) generally supported continued use of precedent agreements, while calling for a streamlining of the permitting process and opposing regional reviews of pipelines or consideration of greenhouse gas emissions.

“EPSA believes the assessment of project need should continue to be based on precedent agreements (i.e., contracts with pipeline project customers), which remain the most objective evidence of market demand for pipeline capacity,” said the group, which represents independent power producers. “EPSA urges the commission not to make the certificate review process more unwieldy or challenging at this time in which significant investment in infrastructure will be needed to meet expected demand and ensure reliability.”

The industry groups proposed only modest changes, for example, improvements to FERC’s website and communications to make it easier for landowners to participate in the process.

Other gas backers cited the economic boost the shale revolution has provided. “The energy renaissance that has occurred in this country, spearheaded by the increased development of natural gas production in Pennsylvania, has increased domestic economic activity, has dramatically improved air quality, and has significantly increased the nation’s energy security and global competitiveness,” said the Pennsylvania Chamber of Business and Industry.

The Marcellus Shale Coalition, which represents about 200 producing, midstream, transmission and supply chain members in the shale play, said producers have been hurt by limited pipeline capacity. “Natural gas produced in some regions of Pennsylvania has sold for over 65% less than natural gas produced and sold in other basins across the nation,” it said. “While efforts continue in Pennsylvania and throughout the Appalachian Basin to grow natural gas demand and usage, it is clear that the natural gas produced in Pennsylvania must also be transported to larger, more established markets where demand is greater,” the group said.

Calls for Change

The attorneys general of Massachusetts, Illinois, Maryland, New Jersey, Rhode Island, Washington and D.C. countered that the commission’s reviews are too narrow. “In assessing project need, the commission generally fails to account for the extent of regional need for new gas capacity or the evolving market for gas demand and relies too heavily on precedent agreements as proof of need for isolated projects,” they said.

“The commission’s single-minded reliance on precedent agreements is also contrary to the existing policy statement, which directs the commission to ‘consider all relevant factors reflecting on the need for the project,’ including studies of projected demand, the market to be served and potential cost savings to consumers.”

The American Antitrust Institute said FERC should evaluate precedent contracts between a pipeline and an affiliated customer differently than one with an unaffiliated customer to support the commission’s policy of promoting competition.

“Importantly, the repeal of the Public Utility Holding Company Act in 2005 removed restrictions on integration between energy companies. Vertical integration, particularly between pipelines and electric or gas distribution companies, can create anticompetitive incentives to engage in conduct that restrains competition and harms consumers. These possibilities can strongly influence the incentives motivating pipeline construction and the effects of affiliate precedent contracts on competition and ratepayers.”

INGAA said the commission shouldn’t differentiate between affiliates and non-affiliate customers agreements “because both appropriately represent market need. While FERC has the authority to investigate allegations of undue discrimination in favor of an affiliated entity if it has any concerns, it is unnecessary for the commission to distinguish between precedent agreements with affiliated and unaffiliated entities.”

The Industrial Energy Consumers of America said the current process “does a good job in identifying the need for new pipeline capacity within the context of serving domestic demand.”

But it said the commission should set a higher bar for pipelines intended to deliver gas for LNG exports. “The LNG export ‘cost versus benefit’ equation is significantly different because the supply is not serving the domestic market, which is the ‘public interest.’ LNG exports serve the public of other countries,” the group said.

Regional vs. Individual Review

Others, including the Nature Conservancy and Virginia’s U.S. senators, Mark Warner and Tim Kaine, said FERC should look at the combined impact of multiple projects in a region and seek to collocate them where possible.

“When multiple projects are being proposed [in the same region], we recommend that FERC consider cumulative impacts through issuance of a programmatic environmental impact statement (PEIS) that would simultaneously consider the purpose and need of each project, the aggregate impacts of all proposed or foreseeable projects on the affected area and the optimal combination of pipelines to deliver gas from the production areas to markets,” the environmental organization said. “This request is consistent with the Council on Environmental Quality guidance on ‘Effective Use of Programmatic NEPA Reviews’ issued on Dec. 18, 2014.”

The senators also agreed with the Conservancy and New Jersey Department of Environmental Protection that FERC should do more to limit pipelines crossing land set aside for conservation.

Some commenters said the commission should not issue final certifications for projects that haven’t obtained all required state and federal environmental permits.

Tolling orders

The senators and others also said FERC should end its use of tolling orders, which keep rehearing requests in legal limbo.

“As a result of this strategy, FERC prevents court challenges to its decision in a meaningful time frame,” said the VOICES coalition, which represents more than 200 organizations opposed to fracking. “Meanwhile, it grants the pipeline company the power of eminent domain and the right to begin and continue construction, all the while knowing that challengers are awaiting their ability to challenge the project in court. The result is that even in those cases where legal challenges to FERC approvals have succeeded, the victories have come too late to genuinely impact the FERC decision already rendered.”

The group cited the nearly yearlong tolling order that preceded a successful court challenge to the TGP NorthEast Upgrade Project. “The court determination that FERC had violated the National Environmental Policy Act by engaging in illegal segmentation and failing to consider cumulative impacts came only after the pipeline was fully constructed and in operation.”

A coalition of environmental groups, including the Natural Resources Defense Council, Sierra Club and Earthjustice, said FERC should use an “all relevant factors” approach in determining project need. Relying almost exclusively on precedent agreements, they said, ignores that “there may be alternatives to the proposed capacity to meet the purported demand, such as using underutilized existing pipeline capacity or alternative, cleaner energy resources.”

The groups also said pipelines may not remain economic for their entire 40- to 50-year lifespan because flat load growth and competition from renewables and distributed energy resources may undermine gas demand.

“An integrated, more comprehensive review would assess the need for new pipelines based on the energy needs of the region(s) directly affected by the project. Such an assessment would examine factors such as existing and proposed pipeline capacity, long-term energy needs and state policies.”

GHG Emissions

Perhaps the most contentious issue FERC will have to navigate is pipelines’ contributions to GHG emissions.

Most of the individual comments filed were form letters from fracking opponents and climate activists in which only the first sentence varied. (“Dear Secretary: Your greed in placing profit ahead of respect for the Earth and its inhabitants is appalling.” “Dear Secretary: We need to keep as many fossil fuels in the ground as possible, and we need to protect our families and our homes from pipeline leaks and environmental damage.” “Fracking is an irresponsible action, which puts our health in danger. It devastates water and land.”)

All five commissioners voted in favor of initiating the pipeline review. But Democrats Cheryl LaFleur and Richard Glick have repeatedly dissented or issued concurrences in protest of the Republican majority’s refusal to consider GHGs on individual projects.

Last August, the D.C. Circuit Court of Appeals ruled that FERC’s environmental impact statement for the Southeast Market Pipelines Project should have included “reasonable forecasting” of the project’s impact on GHG emissions. In May, however, the Republican majority said FERC will no longer prepare upper-bound estimates of GHG emissions when “the upstream production and downstream use of natural gas are not cumulative or indirect impacts of the proposed pipeline project.” Republicans Kevin McIntyre, Neil Chatterjee and Robert Powelson said they were taking the action to “avoid confusion as to the scope of our obligations under NEPA and the factors that we find should be considered” when determining whether a project is in the public convenience and necessity under the NGA. (See FERC Narrows GHG Review for Gas Pipelines.)

Numerous commenters disagreed in their filings this week.

The Harvard Electricity Law Initiative argued that “accounting for the economic risks and environmental harms of downstream and upstream greenhouse gas emissions in a certificate proceeding is consistent with judicial precedent and commission practice.”

The NRDC coalition quoted from a March dissent by Glick, who called climate change “the single most significant threat to humanity.”

“It is difficult to understand how NEPA’s demand that an agency take a ‘hard look’ at the environmental impacts of its actions can be satisfied if the impacts of GHG emissions are ignored,” he wrote.

EEI and individual utilities said, however, that pipelines have helped reduce CO₂emissions by allowing gas generators to replace coal.

The Competitive Enterprise Institute, a conservative think tank, opposed considering GHGs, saying “Saving the planet one gas pipeline at a time is a fool’s errand.

“Worse, importing climate concerns and [social cost of carbon] analysis into public convenience and necessity determinations will fuel spurious ideological controversies, discourage economically beneficial investment in U.S. energy infrastructure and make natural gas prices more volatile.”

July 27, 2018

FERC Grants NYISO Waiver on Grandfathered Tx Contracts

FERC on Wednesday granted NYISO a temporary Tariff waiver to allow it to reserve 256 MW of transmission congestion contracts (TCCs) for load-serving entities in two upcoming auctions while it seeks commission approval of a permanent fix (ER18-1889).

The waiver will allow 14 LSEs to renew grandfathered agreements for TCCs that would otherwise be sold in the Autumn Centralized Transmission Congestion Contract Auction in August and the November 2018 Reconfiguration Auction.

nyiso ferc waiver lses transmission congestion — Location of congested transmission | *NYISO*

Last month, stakeholders approved Tariff changes to allow extensions of historic fixed-price TCCs, which originated from grandfathered agreements before NYISO’s formation. (See “Proposal to Extend TCCs Advances,” NYISO Business Issues Committee Briefs: June 20, 2018.)

The proposal, if approved by the ISO’s Board of Directors, will be filed for FERC approval later this summer.

The commission approved the waiver based on NYISO’s statement “that despite expeditiously pursuing the extension proposal with stakeholders, it is impossible to complete the required process of review and approvals, including commission review, prior to the Autumn Centralized TCC Auction.”

Without a Tariff waiver, the ISO said it would risk overselling the amount of available transmission capacity.

The commission’s July 25 order noted that the waiver is limited to the two auctions and that the 256 MW represent only 1% of average total transmission capacity supporting new TCCs.

The commission said it also relied on the assertion of the New York Municipal Power Agency, a joint action agency of 36 member municipalities, that it needed the waiver to support the long-term supply contracts between its member municipalities and the New York Power Authority.

— Michael Kuser