FERC last week accepted MISO’s plan to allocate Michigan ratepayers $24.6 million in refunds for overcharges stemming from RTO-ordered system support resource agreements imposed on a Wisconsin Electric Power Co. coal-fired plant.
The commission directed MISO to execute the reallocation — which includes interest — over a 10-month period beginning Feb. 28 (ER14-2952-005).
FERC ruled in late October that WEPCo overcharged ratepayers on Michigan’s Upper Peninsula by almost $23 million for agreements that kept the 344-MW Presque Isle coal plant in Marquette, Mich., running in 2014 and early 2015 for reliability purposes. The commission directed MISO to calculate the refunds over the RTO’s objections that it did not provide clear guidance on how to do that. (See $23 Million Owed to Ratepayers in Presque Isle SSR Case.)
Presque Isle power plant | WEPCo
Now, Constellation Energy Group owes the largest share of SSR costs at $13.6 million, followed by Cloverland Electric Cooperative ($6.3 million), Upper Peninsula Power Co. ($4.9 million) and the city of Escanaba ($1.1 million). WPPI Energy is owed $3 million from Michigan LSEs. MISO redacted the monthly refund report in a public version of its filing because it would reveal “insight into monthly load patterns,” according to the RTO.
MISO had proposed to invoice the resettlements as a lump sum on Dec. 19, instead of over the original 14-month timeline. FERC determined that a 10-month distribution was more appropriate because it corresponded with the established April 3, 2014, refund effective date through the Jan. 31, 2015, termination of Presque Isle’s second SSR agreement.
AUSTIN, Texas — Infocast’s annual ERCOT Market Summit once again drew ISO staff, market participants and others for panel discussions on market reform, grid resiliency, resource adequacy, transmission constraints, wholesale price volatility, and integrating utility-scale solar power and battery storage.
Participants Caution Against Market Changes Before Summer
Some of ERCOT’s more vocal members urged caution as the market approaches a summer with projected record demand but with almost 8 GW less in generation after a wave of retirements and delays in planned projects.
The Public Utility Commission of Texas is considering withdrawing reliability unit commitments (RUCs) and reliability-must-run capacity from the operating reserve demand curve (ORDC), a real-time price adder that reflects the value of available reserves and is intended to incentivize resources to produce more energy and reserves. PUC staff said this would ensure that scarcity pricing is accurate and reflective of market dynamics. (See “Commissioners Delay Action on Removing RUCs from ORDC,” Texas PUC Briefs: Feb. 15, 2018.)
But that would be a mistake, said Katie Coleman, legal counsel for Texas Industrial Energy Consumers. “Since 2012, we have spent a lot of time and effort designing the ORDC. We specifically discussed including RMR and RUC capacity. Ideally, the ORDC values should reflect the actual amount of reserves, which accurately reflects the likelihood of load shed. We did a bunch of other things instead, to try and put more money in the market,” she said, referring to RUC’s $1,500 price floor — “which is higher than any unit’s actual cost” — and pricing RMR at the $9,000/MWh cap.
“We’ve built this machine, and we’re about to have a summer where it’s tested. Let’s see how it goes, then come back, and see if there are areas that really need refinement.”
“Part of the problem the last five years is we have never really defined what we are solving for from a reliability point of view,” said Barksdale English, Austin Energy’s interim chief of staff. “What is important to us? Is it short-term interval-to-interval reliability? Is it long-term five-, 10- or 15-year reliability? Until we figure out what we are solving for, having proposed solutions sort of seems like having the cart before the horse.”
English jokingly referred to his “multiple personality disorder” as a generation-owning municipality competing in ERCOT’s wholesale market. “I can get really excited about $9,000/MWh for wholesale generation, but then — oh my gosh — what about my consumers? Then, my City Council gets mad at me because I’m paying too much money.”
Beth Garza, director of the ERCOT Independent Market Monitor, cautioned against blurring the difference between a load-shed event and a blackout. “That’s a very important difference. Those loads are being paid to provide a service,” she said.
“I fully expect many of those services will be called on this summer that have never been called on before. If those services are called on, they’ve been curtailed or are no longer consuming, but they’re being paid for providing a service,” Garza said.
“At what levels does ERCOT take emergency actions? When does load shed begin?” asked Strasburger & Price’s Mark Walker, before answering his own question (when operating reserves reach 1,000 MW). “Hitting the offer cap with only 2,000 MW of available capacity left is sensible. If you look at actual prices when RUC resources are deployed by ERCOT under pressure from load, congestion and intermittent resources swings, the prices today really don’t reflect that we’re in an emergency situation or a serious reliability condition.”
Role-playing Reveals Markets Concerns
In a discussion on how low power prices are affecting the strategies of plant owners in ERCOT, summit organizers asked the panelists to role-play the different aspects of generation investment.
Federal Power Co. CEO Steve Gilliland, filled his natural role as a developer, and Tom Rose, CEO of Clean Energy Technology Association, played the investor. That left Cratylus Advisors’ Mark Bruce, who represents Southern Cross Transmission in its bid to become the ISO’s first DC tie operator, to play the regulator.
Asked what kind of signals the ORDC was giving investors, Gilliland said, “It’s not giving signals big enough and substantial enough.”
“What drives the financier and developer is cash and cash flow,” he said. “I don’t believe that system is giving a clear enough signal for a long enough period of time that convinces me new generation is warranted. I don’t believe it will be allowed to be a significant enough number. It’s going to like moving the deck chairs around on the Titanic.”
“As the regulator, that statement scares me because that ship didn’t make it,” Bruce deadpanned. “The ORDC was not intended to be a substitute for scarcity pricing. It is a construct intended to correct the anomalies in pricing that result from out-of-market actions of the grid operator.
“I applaud the Texas commission for resisting the call to pad the ORDC,” Bruce continued. “That doesn’t help the fundamentals. We’ve had significant periods of time where the system is overbuilt, and the prices will be, and should be, in the dirt during those periods. And that’s the rub, a political rub. The economically optimal reserve margin is quite a bit smaller than the official, cushy planning reserve margin. We’re about to live in the gap between the two, and the political leadership of the state is going to have to decide whether to let the market speak. The economics will reveal in themselves, and then the politics will play catch-up.”
Rose, reminding the audience that he was playing the financier, said, “All this is fairly interesting. Existing generators are going to have a great Christmas this August, but I am going to hold off on new investment until we see how the summer works out.
“I don’t think anyone will argue we’re moving into unchartered waters. That excites me. It might be a risk to some, but it’s a reward to me. If there are involuntary disconnections or if prices go up or down, you’re going to see a governmental reaction,” Rose said. “Reliability the last 10 years has been taken for granted. I already hear people talking about reregulating the market. Mark and I know that’s not going to happen. As he said, ‘There is no Plan B.’”
Generators: ORDC Won’t Incent New Generation
Generation owners in ERCOT debated the effectiveness of the ORDC, one of several pricing mechanisms the ISO says will help respond to tightening reserve margins this summer. (See ERCOT: Tight Summer Margins No Cause for Alarm.)
RTO Insider’s Tom Kleckner moderates a panel on ERCOT wholesale price volatility during Infocast’s ERCOT Market Summit. Panelists include (l-r) Skylar Resources’ Gerald Balboa, Citigroup’s Yashar Barut, ERCOT’s Kenan Ögelman and Engie Resources’ Andrew Elliott. | Infocast
“The ORDC, which is a scarcity pricing mechanism, is absolutely working as designed,” said Dynegy’s Bob Helton during a panel discussion on resource adequacy. “The question is, is it getting us to where we want to be, which is reliability equilibrium and economic equilibrium?”
The Lower Colorado River Authority’s Randa Stephenson said the ORDC should not be seen as a signal for additional generation development. Continued growth in wind generation is expected to pick up much of the slack for recent retirements of baseload generation, and while 2018 futures are trading around $140/MWh, the market has already considered the plant closings by Vistra Energy and others. (See Vistra Energy to Close 2 More Coal Plants.)
“Is there enough scarcity to signal a generation buildout? No, not even a peaker,” Stephenson said. “If you look out into the future, the market knew Vistra was going to happen. Summer of 19, 20 prices didn’t move up that much. I don’t think the signals are out there to justify new build.”
Stephenson said demand response mechanisms are having a greater effect on the market.
“As a generation owner … ORDC is icing on the cake,” she said. “You see a lot of demand response looking at chasing those high-demand periods. You see a drop of 2,000 MW, and that takes away the scarcity prices you were anticipating.”
“ORDC was never introduced, never is and never will be a resource adequacy tool,” Helton said. “It’s for scarcity pricing, a poor man’s co-optimization. It does help with missing money and equilibrium in the market. The correct place for reserves to be is an economically optimal reserve margin. You will likely have load-shed events, but that’s the economical thing to do.”
Susan Pope, managing director of FTI Consulting’s economic practice, told attendees during her keynote address that she and her coauthor on a report recommending ERCOT market reforms believe that the state’s transmission planning policies have “materially” raised costs.
Pope said Texas’ Competitive Renewable Energy Zones (CREZ) initiatives, a $7 billion program that built 2,800 miles of new transmission to deliver West Texas wind energy to the state’s urban centers, was an out-of-market investment “not being made by at-risk investors who need to recover the full costs of their investment.”
CREZ was part of more than $10 billion in transmission investments that have been added to total system costs over the past five years, she said.
“ERCOT regional transmission planning favors transmission for reliability problems, using very conservative assumptions for new generation,” Pope said. “The analysis only includes resources that have committed to construction. Transmission investments will be identified and will pre-empt market-based generation solutions driven by energy-only prices, that could be alternatives to solving reliability problems.
“The over-investment in transmission is partly because of the long lead times to build transmission,” she said. “Those planning can end up with extremely expensive solutions to solve reliability. Continuing to build this transmission reduces energy prices because it resolves all the congestion before it has a significant effect on prices.”
NRG Energy and Calpine commissioned Pope and William Hogan, research director of the Harvard Electricity Policy Group, to write a report assessing ERCOT’s energy-only design. The report asserts that subsidized renewable resources, socialized transmission costs and the lack of local scarcity pricing have “exposed areas where there is a need for adjustments” to ERCOT’s pricing rules. The Texas PUC held two workshops last year to discuss the report and other potential market reforms. (See ERCOT, Regulators Discuss Need for Pricing Rule Changes.)
During a discussion on transmission congestion constraints and how to address them, Brad Schwarz, Hunt Power’s director of system planning, described the CREZ initiative’s unintended consequences.
“CREZ was building transmission ahead of the generation, in the hopes the generation would come. It has happened,” Schwarz said. Then came the state’s oil and gas boom in recent years, he said.
“We would have been struggling to serve those loads without the CREZ,” Schwarz said. “We were able to serve more oil and gas load and bring more economic development to the state of Texas. You never really undervalue a transmission line. Once it’s out there, it finds value.”
Energy Storage Offers Solution to Congestion Issues
Kip Fox didn’t hide his disappointment over Texas regulators’ recent rejection of an American Electric Power request to connect a pair of utility-scale battery facilities to the ERCOT grid. AEP’s application ran into opposition from consumer organizations and market participants who argued that allowing the assets to be included in the regulatory base would harm competition. (See “Staff Opens Battery-Storage Rulemaking,” Texas PUC Briefs: Feb. 15, 2018.)
“We had an alternative to building a long distribution line. It was a $1.6 million solution to a $12 million problem,” said Fox, president of Electric Transmission Texas, a joint venture between AEP and Berkshire Hathaway Energy subsidiaries. “Unfortunately, since those [applications] were denied, without prejudice, we’re kind of back to square one.”
He said with batteries’ ability to provide frequency support and resolve overloading problems, “it makes more sense to run a battery eight to 10 times a year, rather than building a line.” Fox suggested Fluence Energy’s use of a portable battery in downtown Indianapolis presents a possible solution to congestion issues.
“We would like to move a battery around and solve that problem,” he said. “When the congestion is gone in five years because a transmission line hasn’t been built, we will have saved the ratepayers a lot of money.”
Tim Ash, Fluence’s market director for the eastern U.S., said other RTOs are wrestling with the same concerns over battery storage ownership and its effect on markets.
“There’s a much, much bigger market for energy storage,” Ash said. “It solves a reliability issue, which occurs maybe 10 times a year. The economic benefits are there today. The question is how to get the rules to unlock those benefits.”
FERC last month directed RTOs and ISOs to allow energy storage resources full access to their markets, an order that does not apply to ERCOT (RM16-23). (See FERC Rules to Boost Storage Role in Markets.) Asked if FERC’s directive might influence the PUC, which regulates ERCOT, to follow suit, Fox said, “Hell, yeah!”
“I’ve seen many times where the commission defaults to where FERC opens up the rules,” Fox said. “I find those rules are sometimes a little behind, sometimes a little ahead. There will be some pressure at all levels of the [state] government.”
Jack Farley, CEO of Apex Compressed Air Energy Storage, pointed to a 2012 PUC order that allows energy storage resources in ERCOT to pay wholesale prices for recharging, with no retail or transmission or distribution fees. “The energy market averages 40,000 MW and the ancillary services market is about 5,000 MW. In terms of participating in ERCOT energy and ancillary service products, I don’t think there are barriers today for energy storage resources,” he said.
“We will see energy storage adopted early,” said a more optimistic John Bonnin, vice president of energy supply and market operations for San Antonio’s CPS Energy. “As the technology improves, we will see it displace other applications in other parts of the market. If we meet again in five years, every one of us around here will have some sort of storage on their system. We all have to get smarter about the effect all that capacity will have on pricing, fuel and dispatch. It’s going to be disruptive.”
Developers See Bright Future for Texas Solar
A panel of solar developers gave high marks to the Texas market, which could see up to 8 GW of solar growth over the next few years.
“Texas is attractive because of low pricing. Wind is the headline, but at the same time, if the load continues to grow, we can make the case that there’s a match there for solar too,” said Andrew Fay, origination manager for First Solar.
Shalini Ramanathan, vice president of origination for RES Americas, said price pressure “is the reason we’re seeing so much development in West Texas and with large projects. If we can be competitive, we can do more 20-MW projects in other parts of the state. I think there’s a bias to larger West Texas solar.”
Spivey Paup, Recurrent Energy’s development director, said even West Texas, with its oil and gas infrastructure, can pose challenges.
“But once you get out of the Permian Basin, that complication goes away,” Paup said, referring to Texas’ rich petroleum fields. “We need to find a balance between strong resources and development complications. Renewables and solar were born and bred in California, but we can blow them up to scale and send California packing.”
Charlie Hemmeline, executive director of the Texas Solar Power Association, said current rules have resulted in “steady interest” in sun-powered generation in the state.
“We’re not going to ask for new polices or mandates or incentives,” he said. “We want it to work the way Texas wants it to work. ‘Don’t do anything bad to us’ is the primary policy ask.”
EVs, With or Without Drivers, are Coming
During a discussion of changing perspectives among end-use customers, Rob Threlkeld, General Motors’ global manager for renewable energy, noted he had driven from Detroit to Lansing, Mich., without once touching the steering wheel of his Cadillac CT6, thanks to its Super Cruise semi-autonomous driver-assistance system. The car comes in a plug-in version in addition to four- and six-cylinder engine models.
“In a year, the driver will touch the steering wheel much less,” Threlkeld predicted.
He had a believer in Champion Energy Services CEO Michael Sullivan, who owns a Tesla. He said the more mainstream CT6, which starts at about $85,300, will be more broadly available and easier to purchase than the special-order Tesla models.
“When you order Tesla, it’s like ordering an Italian shoe from a cobbler in Milan,” he said.
Both Threlkeld and Sullivan agreed that electric vehicles pose a sea change for the electric industry.
“We have been working closely with a lot of utilities, especially those progressive ones that are really interested in this space. It’s load growth, and that interests them,” Threlkeld said.
“If the projections are right, my teenage kids will never drive an internal-combustion car,” Sullivan said. “If everybody’s driving an electric car, that’s a major change to the industry, especially if somebody can capture storage in a really dense way.”
In two orders issued on the same day last week, FERC both vacated and reinstated MISO’s entire resource adequacy construct, ultimately leaving the RTO’s current capacity auction format — and past auction results — undisturbed.
FERC’s two Feb. 28 decisions concurrently reversed its 2012 acceptance of MISO’s resource adequacy rules (ER11-4081) and accepted the RTO’s refiling of the rules (ER18-462).
To protect its market from “potential disruptions,” MISO in December pre-emptively refiled its entire resource adequacy construct in response to the D.C. Circuit of Appeals’ ruling that FERC overstepped its “passive and reactive” role when it prescribed revisions to PJM’s minimum offer price rule. MISO was concerned about the impact of that decision on some of the resource adequacy rules that had been guided by FERC’s recommendations. (See MISO Seeks FERC Reapproval to Keep RA Rules Intact.)
Following the PJM decision, the D.C. Circuit granted FERC a voluntary remand to once again consider MISO’s 2011 market revisions.
In the order on remand, FERC said in light of the court’s PJM decision, “the modifications set out in the [resource adequacy orders] could be considered to be major modifications to MISO’s 2011 filing. Accordingly, because we cannot find MISO’s 2011 filing to be just and reasonable without our modifications, we reverse the commission’s conditional acceptance of MISO 2011 filing, and we reject MISO’s 2011 filing in its entirety.”
FERC at that time rejected MISO’s proposed mandatory auction requirement and minimum offer price rule and ordered the RTO to phase out grandmother agreement provisions after the 2014/15 auction. Taken together, the revisions “would likely be considered to result in an ‘entirely different rate design’ than both MISO’s proposal and MISO’s prior rate scheme,” FERC said, acknowledging it had exceeded its authority under the Federal Power Act, “notwithstanding that MISO consented to those revisions.”
No Auction Do-Overs
However, FERC found that rerunning the last five years of MISO’s Planning Resource Auction under the pre-2011 monthly auction rules would be infeasible and unnecessary.
“Such a remedy would be extremely complex, subject to controversy and further litigation, and cause significant disruptions and burdens,” the commission said. “It would be highly difficult, if not impossible, for the commission or MISO to reasonably provide retroactive relief, by rerunning the auction for the 2013/14 planning year through the present.”
The commission then addressed MISO’s refiling, determining that the RTO’s current auction format should remain unchanged.
MISO Independent Market Monitor David Patton used the refiling as an opportunity to again urge FERC to order the RTO to employ a sloped demand curve in its capacity auction in order to produce more efficient pricing. (See MISO Monitor to FERC: Order Sloped Demand Curve.)
But the commission said MISO’s vertical curve was just and reasonable, noting that 90% of load is served by vertically integrated utilities. It said that, at any rate, pricing takes a backseat to the main objective: maintaining reliability.
“We … disagree with the Market Monitor’s contention that a vertical demand curve leads to prices that are not just and reasonable by failing to recognize the diminishing marginal benefits of excess capacity. MISO’s resource adequacy construct was developed to ensure that [load-serving entities] in MISO acquired sufficient capacity each year to maintain the one-day-in-10-year reliability standard. Although certain constructs may value capacity beyond that amount, doing so is not essential to MISO’s construct fulfilling this principal objective,” the commission said.
MISO maintains that its vertical demand curve and its annual resource adequacy survey with the Organization of MISO States “combine to provide just and reasonable signals.”
MISO potential GW additions according to 2017 OMS MISO annual survey | MISO
The commission also dismissed several other protests from stakeholders, including complaints that supply offers above $25/MW-day (about 10% of MISO’s cost of new entry) are read as an attempt to exercise market power under current capacity auction rules and that LSEs participated in price suppression in the 2017/18 auction.
FERC instead said that 2017/18’s low clearing price of $1.50/MW-day should be taken as the simple effect of supply and demand in MISO.
“The low capacity prices, where they have arisen in MISO, accurately reflect MISO’s capacity surplus. The fact that prices have not signaled to independent generators a need to build, retrofit or even simply maintain existing resources is more indicative of a well-functioning capacity procurement construct than it is of an unjust and unreasonable construct,” the commission said.
PJM is experiencing an “unprecedented” switch from coal- to gas-fired generation while also managing the replacement of aging transmission infrastructure, staff concluded in the RTO’s annual transmission planning report.
The RTO received deactivation notices for 4,588 MW of generation in 2017, bringing the total since the end of 2011 to 34,967 MW. Deactivation requests in the eight years prior totaled 11,000 MW.
PJM greenlit $5.8 billion in transmission spending last year. That paid for 198 “baseline” projects to ensure compliance with NERC, regional and local transmission owner planning criteria, and 341 “network” projects to interconnect new generating stations. According to the RTO’s figures, that comes out to about $16 million per baseline project and about $8.6 million per network project.
On Feb. 14, PJM’s Board of Managers authorized another $397 million in transmission projects, dominated by TOs’ supplemental projects that are triggered by their own planning criteria. Transmission customers have complained about the uptick in such projects, which don’t require PJM board authorization but are included in the Regional Transmission Expansion Plan, because they believe TOs are using them to pad revenues. (See AMP Presses AEP, PSE&G on Transmission Projects.)
The recent approvals include two such efforts in the Public Service Electric and Gas and Dominion Energy territories. PSE&G plans to spend $115 million to construct a 230/69-kV substation with 69-kV ties to the Paramus and Dumont substations, and $98 million to convert the Kuller Road substation to 69/13 kV and construct a 69-kV network between the Kuller Road, Passaic, Paterson and Harvey stations. Dominion will replace existing infrastructure for a total of $50 million.
This chart shows how transmission projects approved over the past four years have transitioned from larger, “backbone”-type lines to smaller lines to address regional issues. | PJM
The remainder of the approvals consist of another Dominion project — $100 million to install three STATCOM dynamic reactive devices at two substations — and $29.5 million in spending spread across projects in the Baltimore Electric and Gas, PPL and Duke Energy Ohio/Kentucky territories.
Last month, FERC ordered PJM’s TOs to change their process for handling supplemental projects after finding the current approach does not comply with Order 890. TOs worked with PJM on the issue and last week proposed a plan to address the commission’s concerns (See related story, PJM, TOs Propose FERC Order 890 Compliance Plan.)
The PJM board has authorized $35.4 billion in transmission infrastructure spending since 1999. Baseline projects represent $27.9 billion of the total, with $7.2 billion authorized to interconnect 84,200 MW generation. Those figures include $181 million in cost overruns for 48 previously approved baseline projects and $540 million authorized for 336 network projects that were canceled after 257 generator interconnection requests were withdrawn, which reduced expenditures below authorized levels.
This chart shows how PJM expects the generation fleet to be transformed over the next five years. | PJM
But the numbers also provide some insight into development trends. PJM said the 2017 projects address market efficiency congestion and solve local reliability issues, and recent history shows a trend toward smaller lines rather than large, backbone-sized construction.
“Flat load growth, energy efficiency, generation shifts and aging infrastructure drivers — among others — continue to shift transmission need away from large-scale, cross-system backbone projects at 345 kV, 500 kV and 765 kV voltage levels,” the report states.
The generation interconnection queue is dominated by gas-fired facilities, and the deactivation list is littered with coal plants, but the fleet won’t be changing too much any time soon. PJM estimates that oil, wind, hydro and solar will all look about the same five years from now in 2023: slightly more than 10% of the total generation fleet.
Nuclear will drop slightly from somewhat less than 20% today to about 18% in 2023. Coal will also be down from around 31% today to about 28%. Gas increases significantly from roughly 40% today to more than 45%. PJM has said it can remain reliable with upward of 86% gas. (See PJM: Increased Gas Won’t Hurt Reliability, Too Much Solar Will.)
FERC last week instituted proceedings to examine the reactive rate schedules of two MISO generating facilities: the 471-MW RockGen natural gas plant in Christiana, Wis., (ER13-1589) and the 555-MW Carville steam and gas cogeneration facility in southeastern Louisiana (ER18-554).
The commission opened a Section 206 proceeding in a new docket (EL18-51) to re-evaluate RockGen’s reactive rates as a result of parent company Calpine’s proposed acquisition by an investor group led by Energy Capital Partners. FERC had accepted RockGen’s $700,000 annual reactive service revenue requirement in 2013.
The owner of the Carville plant, LS Power Development, asked on Dec. 28 for an annual reactive power revenue requirement of more than $1.1 million.
FERC said Carville didn’t provide proper evidence for multiple factors behind its revenue requirement: “Several components of Carville’s revenue requirement are not adequately supported, including, but not limited to, Carville’s fixed [operations and maintenance] expenses included in the fixed charge rate, the Carville facility’s production plant cost components and the accessory electric equipment allocator. Additionally, Carville utilized an outdated federal tax rate and incorrectly applied … methodology in calculating the Carville facility’s balance of production plant cost,” the commission said in its Feb. 28 order.
LITTLE ROCK, Ark. — As the chair of SPP’s Regional State Committee in 2015, Oklahoma Corporation Commission (OCC) Chair Dana Murphy would, without fail, compliment her fellow committee members, regulatory and SPP staff, and other stakeholders for their efforts, no matter how small.
But that’s just Dana Murphy.
“I feel very grateful,” she said about her practice of recognizing others. “The thing is, there’s always going to be a healthy tension between regulators and SPP and the utilities, and I accept that. I accept that as part of the job, whether I’m serving as a commissioner in Oklahoma or representing Oklahoma here on the RSC.
“I don’t try to avoid [the tension]. The challenge with all of this — and it may be hard to believe — is that I’m an introvert who doesn’t like controversy. Yet, how did I get here?”
After serving on the OCC since 2008, and as its chair since February 2017, Murphy has set her sights on the lieutenant governor’s office.
She opened her campaign last July with a prayer in her hometown of Edmond. “I think all of you who know me know that my faith is the biggest part of pretty much everything I do beyond my family,” Murphy said.
Field of Four
Murphy is competing with three other Republicans — state Sen. Eddie Fields, former state party chair Matt Pinnell and “entrepreneurship consultant” Dominique DaMon Block Sr. — for the GOP’s slot in November’s statewide elections. The primary is June 26.
The commissioner has claimed a significant fundraising edge over her three primary opponents, finishing 2017 with $690,000 on hand after shifting nearly $639,000 from her OCC campaign account. Pinnell had $450,000 on hand, but outraised Murphy in the fourth quarter, $113,000 to her $44,000. Fields finished the year with $65,274 in funds; Block had nothing. Murphy’s donors include oil and gas executives, attorneys, insurance executives, lobbyists, real estate developers, bankers and real estate developers.
Murphy’s campaign website pledges “to address the roots of the longstanding problems facing our state, including the budget, education, health care and infrastructure,” but it is light on policy details.
Instead she highlights her Oklahoma roots and writes of putting more than 180,000 miles on her “little blue truck” to attend events statewide and “visit folks just like you.”
A fifth-generation Oklahoman, Murphy grew up on a ranch, graduated from Oklahoma State University with honors and first worked as a petroleum geologist. As Murphy says on her website, her family encouraged her to “do more and be more,” so she earned a night school law degree from Oklahoma City University while working as a law clerk.
The state’s Sooner Poll has yet to release results of the lieutenant governor’s race, but Pinnell appears to be her strongest opponent. Besides his fundraising prowess, he has built inroads with the national Republican Party by working as a campaign manager for the GOP in all 50 states.
Former Missouri Public Service Commissioner Steve Stoll, who served alongside Murphy on the RSC before cycling off the committee and his state’s commission in January, recalled her as “a very hard worker.”
“I know she cared deeply about the state and wanted to ensure her ratepayers were treated fairly,” he said.
“She has deep knowledge of the energy business, and energy is an integral component to the Oklahoma economy,” said SPP General Counsel Paul Suskie, who works closely with the RSC.
After six years as an administrative law judge for the OCC, Murphy won a seat on the commission in a 2008 special election. She was re-elected to full terms in 2010 and 2016 and has seen her workload grow from normal petroleum and electricity issues to ride-sharing companies and seismic activity related to fracking.
“To make really difficult decisions is something I’ve spent nine years on,” she said, referring to reaching consensus with the OCC’s other two commissioners, Vice Chair Todd Hiett and Bob Anthony. “We don’t have the same opinions on a lot of things, yet somehow, we have to find a way to work together to make decisions. You look at the stakeholders that we deal with, with very divergent opinions and decisions … you have to have the ability to try and process all that and make some really difficult decisions that ultimately, everyone is going to be unhappy with.”
Doing More with Less
Complicating matters, Murphy says, is that the OCC has been asked “to do more with less.”
“Our appropriations from the legislature continue to go down, but our authority and responsibility by statute have increased, just in the nine years I’ve been there,” she said.
Some Oklahoma utilities and petroleum companies have complained about the OCC’s delay in resolving rate cases, which has resulted in interim rates being implemented, subject to refund. Oklahoma law allows the commission to implement interim rates if the cases aren’t resolved in 180 days.
OGE Energy has led the complaints against the process, which reached a crescendo when its December 2015 request for $92.5 million was implemented on an interim basis of $69.5 million in the summer of 2016. The OCC gave OGE’s Oklahoma Gas & Electric utility customers a $47.5 million refund when the rate case eventually concluded last April.
“We are investing north of $500 million in our system every year. I think it’s my job to be supportive of the state, but we’ve got to be able to come up with a way to recover that in a timely manner,” OGE CEO Sean Trauschke said last month during the company’s most recent earnings call with analysts.
Oklahoma Gov. Mary Fallin (R) has responded to the outcry by forming a task force to suggest ways to improve the commission’s performance. (See OGE Anticipates Legislative Review of Oklahoma Regulators.) For her part, Murphy says she is hopeful the task force will increase awareness of the OCC’s challenges and responsibilities.
Lieutenant governor may not be Murphy’s ultimate goal. Oklahoma media note the position is seen as a stepping stone to the governor’s mansion. Case in point: Lt. Gov. Todd Lamb, an early frontrunner for this year’s GOP’s gubernatorial nomination, is now running second to Oklahoma City Mayor Mick Cornett in a crowded field. They are battling to replace the term-limited Fallin, who was elected governor in 2010 after previously serving as lieutenant governor and a U.S. representative.
Murphy, whose term ends in 2022, said she will continue to represent the OCC on the RSC and serve at the commission during her campaign for higher office. As she put it, “I’m here until I’m not here.”
FERC should stop issuing new cybersecurity standards to allow the electric industry to develop innovative defenses to vulnerable industrial control systems — and the National Guard should be ready to respond if an attack succeeds, witnesses told the Senate Energy and Natural Resources Committee on Thursday.
Walker
The panel heard from Assistant Energy Secretary Bruce Walker, a former National Security Agency cyber sleuth, the CEO of the National Rural Electric Cooperative Association (NRECA) and two academics in a nearly two-hour hearing. Chairman Lisa Murkowski (R-Alaska) opened the hearing by asking for advice on what Congress should do after giving FERC the power to issue mandatory reliability standards (in the Energy Policy Act of 2005) and making the Department of Energy the federal agency in charge of responding to attacks on the grid (in the 2015 Fixing America’s Surface Transportation Act).
Murkowski
Robert M. Lee, who founded industrial cybersecurity company Dragos with two other former NSA experts on industrial threats, told the committee that the critical infrastructure protection (CIP) standards mandated by FERC through NERC had made “the North American Bulk Electric System the most resilient and well defended in the world.”
But he said FERC and NERC should not issue any new CIP regulations for three to four years. “This would allow companies to catch up with the current regulations … [and] allow the electric asset owner and operator community to spend a period of time innovating and thinking of new best practices informed by experience. At the end of this period DOE, FERC, NERC and the regulated community can then identify best practices and determine if new regulations are appropriate,” he said.
Lee
“If this recommendation is not palatable, then I would propose an alternative where the regulations are focused instead on program building, such as regulating that a company implement a threat intelligence program, instead of performance-based auditing,” he continued. “This would satisfy the potential desire to move regulations forward while allowing the electric community to develop their own ways forward inside of those programmatic bounds.”
The problem, Lee said, is that “regulations and standards are the trailing end of best practices and only serve as a base level of security. They are not, nor would any regulation be, adequate in the face of determined adversaries. Malware and vulnerabilities are not the threat. The threat is the human adversary, and we cannot regulate them away.”
OT is not IT
Lee and other witnesses emphasized the differences between attacks on utilities’ information technology systems and those on operational technology systems such as supervisory control and data acquisition (SCADA).
Sanders
“Fortunately, the successful attacks to date have largely been concentrated on utility business systems, as opposed to monitoring and control systems, in part because the operational technology systems have fewer attack surfaces, fewer users with more limited privileges, greater use of encryption, and more use of analog technology,” said professor William H. Sanders, head of the Department of Electrical and Computer Engineering at the University of Illinois at Urbana-Champaign. “However, there is a substantial and growing risk of a successful breach of operational technology systems, and the potential impacts of such a breach could be significant.”
Walker, who heads DOE’s Office of Electricity Delivery and Energy Reliability, also made the distinction. “Power systems must operate continuously with high reliability and availability. Upgrades and patches can be difficult and time-consuming, with components dispersed over wide geographic regions,” he said. “Further, many assets are in publicly accessible areas where they can be subject to physical tampering. Real-time operations are imperative, and latency is unacceptable for many applications. Immediate emergency response capability is mandatory and active scanning of the network can be difficult.”
New DOE Cyber Office
Last month, DOE announced it was merging its Infrastructure Security and Energy Restoration (ISER) division and Cybersecurity and Emerging Threats Research and Development (CET R&D) division into the Office of Cybersecurity, Energy Security and Emergency Response (CESER).
Walker said CESER “will enable more coordinated preparedness and response to cyber and physical threats and natural disasters. This must include electricity delivery, oil and natural gas infrastructure, and all forms of generation.”
President Trump has requested $95 million in fiscal 2019 for the office “with a focus on early stage activities that improve cybersecurity and resilience to harden and evolve critical grid infrastructure,” Walker said. “These activities include early stage R&D at national laboratories to develop the next generation of cybersecurity control systems, components and devices including a greater ability to share time-critical data with industry to detect, prevent and recover from cyber events.”
Acts of War
Matheson
Jim Matheson, CEO of the National Rural Electric Cooperative Association (NRECA) and a former congressman (D-Utah), decried “far-fetched scenarios [and] sensationalized claims” about the risks to the grid.
“The scenarios most publicized are rarely reflective of the real threat environment and disproportionately emphasize the highest consequence scenarios that are the least likely to occur,” he said. “Many of the more dramatic scenarios would constitute acts of war on the United States and would directly impact more than just the electric sector.”
No Cyber Fire Departments
Endicott-Popovsky
Such an event would call for the National Guard, said Barbara Endicott-Popovsky, executive director of the Center for Information Assurance and Cybersecurity at the University of Washington.
Endicott-Popovsky said Congress should pass a bill that would establish National Guard Cyber Civil Support Teams of up to 10 members in every state and territory to serve as first responders following an attack and bridge the gap between federal and non-federal efforts. The cyber CSTs would be under the direction of governors and state adjutant generals, under legislation (H.R.3712) introduced last September in the House of Representatives and referred to the Subcommittee on Military Personnel in October. The bill is modeled after a program created by the Washington National Guard.
“Civilians are used to calling 911 for emergencies of all kinds, but who do you call in the event of a major cyber outage? There are no cyber fire departments,” she said. “The [Department of Defense] is prepared to defend their own networks to support their missions, but who will step in on the civilian and private sector sides to restore power, to assist with maintaining our communities? There is no one. This vacuum is a national security threat.
“Public and private, we have two very different missions: The mission of the military is to protect the Homeland, and the mission of private sector to innovate and maintain profitability for the board and shareholders,” she continued. “Blending missions is not an easy task, but the time has come where the cost of not integrating resources significantly outweighs the benefits of maintaining independent response plans. This is especially true given the workforce shortage of cyber specialists.”
Endicott-Popovsky said it will take a national effort comparable to NASA’s goal of landing on the moon to fill the shortage of cyber talent. “While cybersecurity education has been called a national priority by some, there still are hundreds of thousands of cybersecurity jobs going unfilled, and the gap will take a long time to close,” she said.
The good news: Cybersecurity is becoming a profession, with 32 distinct career paths identified under the National Initiative for Cybersecurity Education (NICE) framework, she said.
How Congress Can Help
In response to Murkowski’s question about Congress’ next steps, Matheson called for more timely information sharing by government after incidents such as the December 2015 attack on Ukraine’s grid.
He also called for legislation allowing the FBI to conduct background checks on utility industry personnel performing critical functions, continued funding for R&D and aid to small and medium utilities for improving their security.
Illinois’ Sanders said DOE, the Department of Homeland Security and researchers should focus their R&D and demonstration projects on developing six capabilities: “continuous data collection, fusion of sensor data, visualization, analytics, restoration and post-event tools.”
“These capabilities can be achieved only if academia, industry and government work closely together in a focused research and development program,” he said.
FERC on Wednesday accepted ISO-NE’s proposed new capacity bilateral transaction and a revised materiality threshold for determining whether a resource can satisfy its capacity supply obligation (CSO) (ER18-455).
The grid operator proposed the annual reconfiguration transaction (ART) to replace the capacity market’s existing bilateral contracting mechanism, the CSO bilateral. The RTO said the change was needed to accommodate its transition to marginal reliability impact-based demand curves (MRI), which are based on the expected improvement in reliability from adding incremental capacity.
The commission’s Feb. 28 order said that the ART will give resources looking to replace their CSO through a bilateral contract more flexibility. “The ART mechanism will accommodate even or uneven exchanges within the same zone or across constrained zone boundaries, even where exchanges previously were prohibited, while accounting for the actual net impact on reliability in a manner that does not disadvantage suppliers or consumers,” the commission said.
| Energyzt, ISO-NE
FERC also agreed to ISO-NE’s proposal to change how it determines when to submit demand bids in the third Annual Reconfiguration Auction (ARA) for resources that have a significant decrease in capacity. The RTO said its previous threshold — 20% of its CSO or 40 MW, whichever is lower — produced outcomes that focus on relatively small deficiencies and ignore relatively large deficiencies. For example, a 35-MW deficiency from a 100-MW resource would be subject to the RTO’s mandatory demand bid rule, while the same deficiency from a 200-MW resource would be exempt.
Under the new rules, the RTO will intervene when a resource’s capacity decreases by 10 MW, or 10% (but at least 2 MW), whichever is lower.
The commission dismissed FirstLight Power Resources’ request to eliminate the minimum 2-MW floor for the threshold. “We do not find any evidence that the proposed changes will result in undue discrimination among resources or compromise the integrity of the capacity markets, as FirstLight claims,” it said. The proposed thresholds “reasonably balance the impact on large and small resources, while reducing ISO-NE’s administrative burden.”
FERC also rejected a request from New England generators Exelon, CPV Towantic and NRG Power Marketing that the mandatory demand bid changes take effect in Forward Capacity Auction 9, rather than FCA 11.
| Energyzt, ISO-NE
Because it found the “proposal, including its implementation date, to be just and reasonable, we need not consider whether an alternative proposal is also just and reasonable,” the commission said.
There was no evidence that the new threshold will undermine the integrity of the capacity market, the commission said. “For all resources, regardless of the significant decrease threshold, the general obligations associated with having a CSO continue to apply.” The existing thresholds have not undermined the integrity of the capacity market or sent a signal that it is appropriate to intentionally overstate a resource’s capacity values, it said.
“We find it is reasonable to expect that the revised rules, which ISO-NE expects to affect a similar amount of capacity as the existing rules, likewise would not undermine the integrity of the market,” the commission said.
FERC last week rejected the New York Public Service Commission’s request to rehear a November 2017 decision granting NextEra Energy Transmission New York (NEET NY) a 50-basis-point adder for participating in NYISO.
The ISO in October selected the company’s Empire State Line proposal to address a need for new transmission in western New York.
Empire State Transmission Line | NextEra Energy Transmission
FERC’s Feb. 28 order dismissed the PSC’s argument that a participation adder — or membership incentive — was unnecessary because NYISO selected NextEra as part of its transmission planning process, leaving the company no choice but to turn over operational control of its transmission to the ISO (ER16-2719).
The federal commission countered that the incentive recognizes the consumer benefits, including reliability and cost benefits, that flow from ISO membership.
Section 219 of the Federal Power Act provides for incentives to each transmitting utility or electric utility that joins an RTO/ISO, and incentive-based rate treatments benefit consumers by ensuring reliability and reducing the cost of delivered power, FERC said.
Empire State Transmission Line | NextEra Energy Transmission
“We consider an inducement for utilities to join, and remain in, transmission organizations to be entirely consistent with those purposes … and the best way to ensure those benefits are spread to as many consumers as possible is to provide an incentive that is widely available to member utilities … and is effective for the entire duration of a utility’s membership in the transmission organization,” FERC said.
FERC granted NEET NY’s request subject to the return on equity with the adder being within the zone of reasonableness, it noted.
SAN DIEGO — A joint effort between Peak Reliability and PJM offers Western industry players a chance to design their own market, one that will operate with more transparency than CAISO, PJM CEO Andy Ott said last week.
“The whole key here is the ability of the West to build up its own rules,” Ott said.
The CEO added that PJM’s expertise in coordinating markets and dealing with regional differences in the East will be a major asset in developing a Western market in partnership with Peak.
Having traveled west last week to attend a meeting of the Western Power Trading Forum, Ott sat down with RTO Insider to discuss the new Peak Reliability/PJM Connext market proposal. (See Peak Touts ‘Independent’ Western Market Plan.)
The partnership is galvanizing interest across the industry around a new Western market, but it comes amidst several other major recent developments shaking up the region.
Among them: competing efforts by CAISO to provide reliability coordinator (RC) services and extend its day-ahead capability into the Energy Imbalance Market (EIM). (See CAISO Plan Extends Day-Ahead Market to EIM.)
PJM’s executive spoke frankly about the shortcomings he sees in CAISO, including what he characterized as a relatively closed-door process for addressing market issues, compared with the more stakeholder-driven approach he envisions for the Peak market.
In California, “they have a discussion about a specific issue they are going to change, then they go in a room and make a decision, and they come out and they have a decision,” Ott said. “It’s not done that way everywhere.”
Ott touted PJM’s experience in operating a 13-state, multibillion-dollar energy market in the East. The RTO brings that experience to the effort, while Peak has the real-time reliability model of its territory already completed, he said.
Aside from the market proposals, Peak and CAISO are competing to provide NERC-certified RC services. Shortly after Peak and PJM announced their effort, CAISO dropped Peak as its RC and announced it would offer Western utilities RC services at a lower cost.
Peak CEO Marie Jordan, who also attended the WPTF event, noted that the only non-revocable notice of departure that the organization has received so far is from CAISO. Several Peak customers have announced they will leave, after CAISO issued its notice of withdrawal at the beginning of the year.
Late last month, the Bonneville Power Administration and Western Area Power Administration separately announced they have signed nonbinding notices signaling their intent to depart Peak by the end of 2019. BPA said it is exploring receiving RC services from CAISO, while WAPA is considering SPP and CAISO for some of its balancing authorities.
A business plan for the Peak Reliability/PJM Connext proposal is due at the end of March
Ott noted that the EIM was designed with the specific purpose of giving California a way to export renewable generation and get services back. The market benefits California customers, and he called outside regional participants “guests” in the market.
“I see the EIM, frankly, as a stopgap,” Ott said. “It was created to solve a problem.”
Ott said the business case for the market is being studied and is due to be issued March 30. Peak executives have publicly discussed the potential for the effort to evolve into a full RTO, something Ott says will depend on input from market participants.
“Our mindset is that if we put the PJM name on something, it’s not going to fail. We cannot afford to let it fail,” Ott said.
