SPP last week reiterated its plans to recover the costs of a NERC penalty for reliability violations by dipping into its employee compensation pool (ER19-97).
In a heavily redacted filing shared with SPP stakeholders at 4:47 p.m. on July 3 — just before the Independence Day holiday — SPP said its board of directors determined the best way to recover the penalty’s costs was to “offset the cost with funds that were approved and allocated to the SPP employee compensation pool,” rather than charging members and market participants.
SPP paid the fine, which NERC approved in the RTO’s role as a registered entity (RE), last year out of a 2017 surplus “that was sufficient to pay the full amount of the monetary penalty.”
The RTO said recovering the penalty cost from authorized employee compensation funds “essentially holds members, market participants, and customers harmless from the cost of the reliability penalty.”
SPP’s headquarters in Little Rock, Ark. | ACE Glass
The amount of the fine and the reason for the penalty have not been disclosed. SPP requested confidential treatment for the filing as privileged material and/or critical electric/energy infrastructure information “in order to mitigate potential risks to the reliability of the bulk-power system under SPP’s control.” Seven of the 29 pages in SPP’s filing were fully redacted and two pages were partially redacted.
SPP told RTO Insider that company policy keeps it from commenting on “such matters.”
“Anything we could say publicly is already stated in the filing,” spokesman Derek Wingfield said.
In FERCOrder 672, the commission said that NERC violations “generally will be made public after the matter is filed … as a notice of penalty or resolved by an admission that the user, owner, or operator of the bulk-power system violated a reliability standard or a settlement or other negotiated disposition.”
But SPP noted the order also allows a filer, if it believes information on the violation “could jeopardize the security of the bulk-power system if publicly disclosed,” to “fully support” its confidentiality claim in the non-public version of its proposal to recover penalty costs.
SPP added the language in its filing after FERC last year denied its request for waivers from regulations guiding the confidential treatment. The commission said SPP must allow intervenors to sign nondisclosure agreements to access information that the RTO believes should be withheld from the general public. FERC said its CEII regulations “recognize that intervenors in a commission proceeding … may need access to information that the applicant believes should be withheld from disclosure to the general public in order to participate effectively in the proceeding.” (See FERC Rejects SPP Confidentiality over NERC Fine.)
SPP is a NERC RE in the Midwest Reliability Organization and Western Electricity Coordinating Council. It is required to compliance with NERC reliability standards for its roles as a balancing authority, planning authority/planning coordinator, reliability coordinator, reserve sharing group, and transmission service provider.
Under Attachment AP of SPP’s Tariff, the RTO may seek recovery of reliability penalty costs by either directly assigning them to the responsible members or market participants or by allocating the costs to all members or market participants.
As justification for its decision to pay the penalty from its employee compensation fund, SPP cited FERC’s 2008 “Guidance Order,” in which the commission said RTOs could tie employee compensation to compliance with reliability standards as one possible way of “prevent[ing] the incurrence of penalties.”
SPP cited the order’s statement that “Bonuses and other incentives received by senior management could also be made contingent on penalty-free operations” and that in reviewing RTO filings, FERC will consider whether the RTO has implemented “personnel policies that place incentives on employees and management to comply with the rules or risk adverse actions.”
SPP said using the existing surplus to pay the reliability penalty “promptly” was an appropriate and reasonable action. The RTO said, “Doing so enabled SPP to pay the penalty in a timely manner as required without having to expend additional time, effort, and resources to file for commission authorization to allocate the costs … prior to paying the penalty, and then invoicing and collecting the funds from the same entities who contributed to the 2017 surplus” through their payment of SPP’s administrative charges.
PJM staff called June an uneventful month for grid operations, despite 23 emergency procedures — including 21 post-contingency local load relief warnings (PCLLRWs) and three hot weather alerts.
PCLLRWs are utilized in the coordination of post-contingency load shed plans between PJM and transmission owners. June’s events occurred in the RTO’s western transmission zones, including Commonwealth Edison, Eastern Kentucky Power Cooperative, American Electric Power, American Transmission Systems Inc., Pennsylvania Electric, and Duke Energy Ohio and Kentucky. There was one PCLLWR on June 25 in the Atlantic City Electric transmission zone for the Chestnae-Moss Mills line.
The hot weather alerts occurred June 27-29 RTO-wide.
PCLLRW count versus peak load over the last three months | PJM
Black Start Packages Coming Together
PJM’s Janell Fabiano told the Operating Committee on Tuesday that stakeholders will soon present new rules for black start resource fuel requirements.
Stakeholders began meeting in July 2018 to reconsider whether the existing fuel requirement of 16 hours proved sufficient given PJM’s focus on resilience in recent years. The group is also considering ways to mitigate high-impact, low-frequency events across all black start resources and fuel types.
Calpine, PJM and Monitoring Analytics continue to work on three similar plans to define fuel assurance and tweak the hourly reserve requirement. Fabiano said stakeholders will bring the three finalized packages to both the OC and the Market Implementation Committee for votes in the fall. Changes will not move forward without support from both committees, she said.
Non-retail BTM Generation Business Rules
Stakeholders delayed voting on changes to Manuals 13 and 14D that refine responsibilities, processes and procedures related to how PJM manages non-retail behind-the-meter generation (NRBTMG). (See “BTM Generation Rules Preview,” PJM OC Briefs: June 11, 2019.)
The revisions to Manual 13 expand upon what events trigger the use of NRBTMG to include “maximum generation emergency” and “deploy all resources” actions, which address capacity shortages or transmission security emergencies.
In Manual 14D, staff updated Appendix A to clarify generator operational requirements for the reporting, netting and operational requirements of NRBTMG.
The delay allows some stakeholders more time to review the revisions. PJM will seek endorsement at the August OC.
Generation Outages
PJM advanced changes to Manual 10: Prescheduling Operations absent the stability-related modifications called into question at the May 14 OC meeting. (See “Generation Outage Revisions Delayed,” PJM OC Briefs: May 14, 2019.)
Stakeholders instead endorsed the remainder of the changes developed out of the periodic cover-to-cover review of the manual that clarifies outage ticket rules for deactivation and black start resources.
Manual Changes Endorsed
Stakeholders unanimously endorsed changes to the following manuals:
Manual 39: Nuclear Plant Interface Coordination (See “Nuclear Plant Interface Coordination Updates,” PJM OC Briefs: June 11, 2019.)
WASHINGTON — Tom Hassenboehler used to work for Sen. James Inhofe, the Oklahoma Republican who famously brought a snowball to the floor of the Senate in 2015 to make the case that the Earth couldn’t be warming.
Has the level of debate improved since then?
Yes, said Hassenboehler, former chief counsel for energy and environment at the House Energy and Commerce Committee, noting his last bosses in Congress were Reps. Greg Walden (R-Ore.) and Fred Upton (R-Mich.).
“They started off [2019] in hearings with the Democrats … acknowledging climate [change] is real and not wanting to have a science debate anymore and … focusing on what is the solution now,” said Hassenboehler, now with The Coefficient Group. “While it may seem small to some folks, I think it is a big step. … Republicans have to be on the same side — of figuring out what their solution is.”
Republican Colin Hayes, former staff director at the Senate Energy and Natural Resources Committee, also sees a change. “The shift in rhetoric is usually a leading indicator of policy change,” said Hayes, co-founder of lobbying firm Lot Sixteen. “And then it’s a conversation about the policy prescription and what it takes to get the requisite number of ‘yes’ votes to make an actual change. That conversation is underway now in a more energized away than it has been.”
Hassenboehler and Hayes spoke Tuesday on an energy policy panel moderated by former Montana regulator Travis Kavulla, now director of energy policy for the R Street Institute, a “free market” think tank, at the Capitol Visitor Center.
Although the two former GOP congressional aides agreed their party is beginning to shed its climate denial, neither predicted major legislation to address the issue anytime soon.
To pass major legislation, “you need a catalyst that often times comes in the form of a crisis,” said Hayes. “Constituents are just ticked off … and so they pick up their phone and call their congressman. I’ve never seen anything get done on the Hill, at least in the energy space, because it was a means to recognize some aspirational, more wonderful world than the one we have. It is almost always a response to people being ticked off.”
Hassenboehler said Congress is responding not only to their constituents but also to Fortune 500 companies that have begun assessing their climate risks in public disclosures. “And that goes for not just tech companies, but to oil and gas and fossil companies as well.”
Lessons from the Failure of Cap and Trade
What does a solution look like?
The failure of the Waxman-Markey proposal — which cleared the House in 2009 but never received a vote in the Senate — means cap and trade is unlikely to be the centerpiece of any future legislation, Hassenboehler said.
Waxman-Markey may have failed in part because President Barack Obama decided on health care as his top legislative goal, Hassenboehler said. “But … it had more to do with the lack of compromise on the proponents’ side … and their kind of one-size-fits-all solution. They didn’t want to see the Senate … shape that bill in a way that was different from the Waxman-Markey proposal. … If the other side had compromised a little more, they would have gotten it done.
“It did lasting damage, frankly, to the brand of cap and trade, which is an efficient way of managing carbon pollution potentially,” Hassenboehler continued. “You’ve got examples all across the states and in other parts of the world that have cap-and-trade programs. We don’t talk about that barely at all anymore. Could that be a potential piece of the pie in the future? Sure, I still think it could come back, but it’s never going to be the lead in a climate bill again in my view.”
Hayes said a “forgotten” lesson of the episode was “it wasn’t Republicans who killed it.”
“It passed the House; it came over to the Senate, then controlled by [Democrats]. … That gave them the votes they needed on health care. That didn’t give them the votes they needed on cap and trade because of the regional nature of these issues,” with opposition from rural lawmakers concerned about the plan’s cost.
FERC Filling the Gaps
Tuesday’s discussion also touched on FERC’s interpretation of the Federal Power Act’s directive to ensure just and reasonable rates.
“Even though the law talks about rates and charges, FERC has looked at this language over time and said, ‘You know what: If utilities aren’t planning their transmission grid in the right way, if they’re not cooperating regionally to plan the transmission grid, that might lead to rates that are unjust or unreasonable,’” Kavulla said. “‘And therefore, we’re asserting jurisdiction over the way the grid is planned for, paid for and built.’”
Hassenboehler said Congress should be “more assertive” in giving FERC direction, through letters and oversight hearings, such as that held by the Senate Energy and Commerce Committee in June. (See FERC Probed on RTO Governance, Market Issues.)
“The way things are rapidly innovating in the electric space, there’s a lot of tough questions out there that FERC is struggling with … and it really all comes down to the power of states versus the feds. … And there’s been no consensus or leadership on that issue in a while. … I think legislation is building over the next several years for that.”
Hayes said FERC’s interpretation of the FPA is a recognition of the limits of legislation on complex issues. “Congress can oftentimes get itself 80, 90, 95% of the way through to the answer on a policy question or problem and secure the votes that are required to make some associated change. But that last 5% can be the technically challenging, politically challenging [issues]. You may just run out of time to answer the question” in a two-year congressional term.
Hayes said he’d like to see the federal government assert jurisdiction over the environmental performance of electric generation.
“Some folks, states’ rights advocates … don’t want them to have that because they are fine with the [state-by-state] patchwork” of environmental policies.
“But I think that those environmental issues are decidedly global in nature. At a minimum … they are national in nature as policy questions. They’re not confined to a single state. You’ve got to get to all 50 [states], or you haven’t really addressed the issue.”
Hassenboehler agreed there are some issues on which the federal government should assert jurisdiction, noting, “We don’t have 50 different labels for food [ingredients].”
He said Congress should tackle the issue of “how data is utilized in the [energy] system: who gets to collect it; who gets to own it.”
“This is energy data, emissions data, things that are being collected across the energy supply chain,” Hassenboehler said. “There’s a lot of need for some systematic consistency.”
It’s said the Supreme Court won’t grant review to reverse a lower court decision that is “merely wrong.” Don’t waste the court’s resources on error of little consequence.
The opposite of that we might call “scary wrong”: something profoundly wrong and with significant potential consequence.
Such is the case with the Natural Resources Defense Council’s new attack on PJM,1 accusing it of suppressing renewable resources relative to other RTOs, wasting billions of consumer dollars in the process and contending, in effect, that a cheap and reliable zero-carbon future could be ours if entities like PJM would just mend their evil ways.
NRDC is wrong in virtually every claim. And it’s scary because policy based on NRDC’s profound errors would be profoundly misguided. We can’t afford to make a bunch of mistakes in dealing with climate change.
The gravamen of NRDC’s attack on PJM is data it compiled showing that the RTO has added more natural gas (“polluting”) resources than renewable resources since 2012. Per NRDC, other RTOs have done the reverse, adding more renewable resources than natural gas resources. NRDC points to RTOs like SPP and ERCOT as good guys.
The worst error in NRDC’s attack is its complete disregard of the relative renewable resources in PJM versus SPP and ERCOT.3
Does this make a difference? Yes, bigly.
National Renewable Energy Laboratory and Energy Information Administration data confirm what is common knowledge in our industry that RTOs like SPP and ERCOT have vastly greater wind and solar potential resources. Of note, higher percentages of its wind and solar potential resources have been added in PJM than in either SPP or ERCOT. In other words, given the renewable cards it was dealt, PJM (or more accurately the PJM region) is doing a better job.
To show this, we’ll use NREL data by state on the “technical potential” of renewable resources, which reflects among other things environmental and land-use constraints. (This is important because a wind project isn’t going to be built in Philadelphia.) Let’s start with wind (because existing wind gigawatts are several times larger than existing solar gigawatts in the U.S. overall, and many times larger in the states comprising PJM, SPP and ERCOT)
SPP has 26 times as much wind potential as PJM, while ERCOT has nine times as much. | National Renewable Energy Laboratory
NREL data show that PJM has around 165 GW of potential onshore wind capacity, in contrast to SPP’s 4,235 GW and ERCOT’s 1,426 GW.4 This means SPP has 26 times more potential wind than PJM; ERCOT has nine times more potential wind than PJM.
How much wind has been added so far in these RTOs? PJM has 9,428 MW of installed wind capacity,5 SPP has 20,610 MW,6 and ERCOT has 22,051 MW.7
So which RTO has made the most of its potential wind resources? PJM has installed 5.7% of its potential, SPP has installed 0.5% of its potential, and ERCOT has installed 1.5%.8
Thus, given the wind resource cards it was dealt, PJM has done much better than SPP or ERCOT.
How about solar?
The NREL data show that PJM has 7,611 GW of potential utility-scale solar capacity, in contrast to SPP’s 31,543 GW and ERCOT’s 15,308 GW.9 This means SPP has four times more potential solar than PJM; ERCOT has two times more potential solar than PJM.
SPP has four times the potential solar resources of PJM; ERCOT has twice as much. | National Renewable Energy Laboratory
How much solar has been added so far in these RTOs? PJM has 1,800 MW of installed solar capacity, SPP has 180 MW, and ERCOT has 1,858 MW.10
So which RTO has made the most of its potential solar resources? PJM has installed 0.02% of its potential, SPP has installed 0.0006% of its potential, and ERCOT has installed 0.01%.
As with wind resources, given the solar resource cards it was dealt, PJM has done much better than SPP or ERCOT.
Thus the reality: PJM has outperformed its RTO brethren in adding renewable resources given the cards it was dealt.
Stayin’ Alive?
Following on its unsound narrative that PJM has done poorly in adding renewable resources, NRDC looks for a culprit. And it finds one in PJM’s capacity market, which it says is “a tool for uneconomic fossil fuel power plants to get paid enough to stay alive.”
This is absurd. Since the start of PJM’s capacity market, an enormous 25,857 MW of coal generation in PJM has retired, which is more than one-third of all coal generation retirements in the entire U.S. of 70,522 MW over the same period.11
If PJM’s capacity market is a tool to keep uneconomic coal plants alive, then it is failing miserably.
NRDC also fails to explain why (per its data) ISO-NE and NYISO have added more renewable than gas megawatts when both of those RTOs have a capacity market. How can this be, given NRDC’s capacity market thesis?
The reality is that new natural gas and renewables in PJM (and elsewhere) are forcing uneconomic coal plants to retire, causing a significant reduction in carbon emissions per megawatt-hour in the RTO.12
This is what needs to continue.
And Those Extra Billions Paid by Consumers?
NRDC claims that PJM has acquired more resources in its auctions than its “target reserve,” and the “extra totals up to billions of dollars more on customer bills.”
This claim reflects a profound misunderstanding of PJM’s capacity market. When the PJM annual auction “clears” (commits to purchase) resources above its target reserve, the clearing price for all capacity resources goes down. This greatly reduces the total cost of capacity that consumers pay.
In the last auction, for example, if resources had offered prices such that the cleared resources were equal to the target reserve, consumers would have paid $18.7 billion for capacity.13 Instead, because resources offered more attractive prices, more resources cleared but at a much lower price, resulting in consumers paying $8.4 billion for capacity — roughly $10 billion less.14
NRDC has it exactly backward.
Annual Capacity Construct
NRDC says PJM has a year-round capacity requirement that hurts renewable resources for no reason. This is an amalgamation of three errors.
First, PJM in fact permits renewable resources to participate in the capacity market notwithstanding their obvious inability to be dispatchable year-round (or at all).15 NRDC ignores this.
Second, PJM in fact permits seasonal resources to match up to simulate an annual resource.16 NRDC ignores this.
Third, PJM basing the capacity construct on summer peak demand does not mean that PJM overbuys capacity for winter and other periods when peak demand is less. Resources need to be acquired for the overall peak, which happens to occur in the summer. Seasonal capacity variations have been considered and rejected for more than 10 years, with a PJM discussion here.17
If the annual capacity market was reconstructed into seasonal markets, then potentially lower prices in non-summer periods would have to be covered by higher summer prices in order to ensure resource adequacy.
There is no such thing as a free lunch.
Biting the Feeding Hand
It is ironic that NRDC targets PJM’s capacity market. The capacity market has been a bulwark against bailout claims for dirty and uneconomic power plants by enabling a transition to cleaner natural gas and clean renewable generation, while assuring resource adequacy years into the future.
Fantasy and Reality
NRDC is promoting a narrative that a cheap and reliable zero-carbon future is easily ours. This narrative requires bad guys like PJM who must be obstructing an easy path forward.
Reality is different. PJM hasn’t obstructed renewable resources and, in fact, is outperforming its RTO brethren given the renewable cards the region was dealt. PJM’s capacity market (like other RTO capacity markets) doesn’t save uneconomic coal plants, doesn’t impose excessive costs on consumers, doesn’t suppress renewable resources and is a bulwark against bailout claims for uneconomic coal units that should retire.
Dealing with climate change will not be cheap or easy.18 We should get real instead of looking for fall guys.
3- NRDC mentions resource potential as one of many factors in resource development, but then proceeds to ignore it (and all other factors) in blaming PJM’s capacity market, as discussed later.
4- The NREL data are on Table 6 of its report “U.S. Renewable Energy Technical Potentials: A GIS-Based Analysis,” available here, https://www.nrel.gov/docs/fy12osti/51946.pdf. For states partially within an RTO, I pro-rated the potential resource by the land-area portion of the state within the RTO.
8- The math is dividing the installed wind capacity for each RTO by the potential wind capacity for that RTO.
9- Same NREL study, using Table 3 for “Rural Utility-Scale Photovoltaics by State.” As with wind, for states partially within an RTO, I pro-rated the potential resource by the land-area portion of the state within the RTO.
10- Same RTO sources as for installed wind capacity.
15- Per PJM report on the auction: “1,416.7 MW of wind resources cleared the 2021/2022 BRA as compared to 887.7 MW of wind resources that cleared the 2020/2021 BRA. … The nameplate capability of wind resources that cleared in the 2021/2022 BRA as annual CP capacity and/or winter seasonal CP capacity is approximately 8,126 MW, which is 1,407 MW greater than the 6,719 MW of wind energy nameplate capability that cleared in last year’s auction. 569.9 MW of solar resources cleared the 2021/2022 BRA as compared to 125.3 MW of solar resources that cleared the 2020/2021 BRA. … The nameplate capability of solar resources that cleared in the 2021/2022 BRA as annual CP capacity and/or summer seasonal CP capacity is approximately 1,641 MW, which is 964 MW greater than the 677 MW of solar energy nameplate capability that cleared in last year’s auction.” https://pjm.com/-/media/markets-ops/rpm/rpm-auction-info/2021-2022/2021-2022-base-residual-auction-report.ashx?la=en.
16- Per PJM report on the auction: “715.5 MW of seasonal capacity resources cleared in an aggregated manner to form a year-round commitment. This is an increase of 317.5 MW over the 398 MW of seasonal capacity resources that cleared in an aggregated manner in the 2020/2021 BRA.” Same source as preceding footnote.
Shell Energy wants a seat at the GreenHat Energy settlement table, saying it is “uniquely situated” in the proceeding and could bear a disproportionate financial burden based on its outcome.
In its request for rehearing filed Friday, Shell argued FERC erred when it dismissed more than a score of late-filed motions from intervenors seeking to participate in the unwinding of GreenHat’s financial transmission rights portfolio. The company was declared in default in June 2018 after it failed to make good on its mounting losses.
“Departing from longstanding FERC policy against settlements that may have an impact on others not present during the negotiations, the commission has initiated a course of action that will allow a handful of parties to decide” the best way to liquidate GreenHat’s portfolio, Shell said (ER18-2068). PJM has said having to liquidate the portfolio under existing rules could cost members $430 million or more.
On June 5, the commission gave RTO members 90 days to settle disputes about how to move forward before kicking off a paper hearing on PJM’s request to clarify FERC’s ruling rejecting the waiver. (See FERC: PJM Settle Disputes Before GreenHat Hearing.)
GreenHat’s significant growth in exposure and MTA loss. | PJM
On Monday, Chief Administrative Law Judge Carmen A. Cintron canceled a settlement conference scheduled for Wednesday “to allow more time to prepare for future conferences.” Cintron said the cancellation would not affect a conference set for July 26.
Shell was among more than 20 petitioners that filed after the comment period for PJM’s waiver passed. FERC rejected the late filings, saying none demonstrated “requisite good cause for late intervention.”
But Shell says a PJM Tariff provision caused its tardiness, a circumstance that it says none of the other petitioners face.
“Shell Energy entered into three bilateral transactions involving transfers of a portion of GreenHat’s now defaulted FTR portfolio to Shell Energy and back to GreenHat,” the company wrote. “As a result, PJM informed Shell Energy that it would seek guarantee and indemnification from Shell Energy for the portion of GreenHat’s FTR portfolio that was so transferred. Liquidation of GreenHat’s FTR portfolio could substantially affect the amount sought by PJM under the guarantee and indemnification claim.” (See Shell Energy Seeks to Avoid Liability in GreenHat Trades.)
Shell says PJM didn’t tell the company it would be subject to this clause until after the comment period passed and that no other party participating in the settlement discussions could “adequately represent its interests.”
“Because any settlement to resolve issues related to the massive GreenHat default will necessarily impact all PJM members subject to default allocation assessment (and, in turn, ratepayers), excluding Shell Energy and others from settlement negotiations among only a few parties is unlikely to result in a settlement that is in the public interest,” the company said.
Shell further argued that its participation would not “unfairly prejudice or burden” the allowed parties, none of whom opposed its intervention.
“As Shell Energy originally explained, it is not presenting new evidence or law, nor altering any previously established procedural schedule,” the company wrote. “Shell Energy accepts the record as it stands.”
SACRAMENTO, Calif. — The wildfire package that Gov. Gavin Newsom asked lawmakers to push through in a week cleared two key committees Monday and sailed through the State Senate, 31-7, in an extraordinarily accelerated process.
Some lawmakers complained they hadn’t had time to read the voluminous bill, which was printed late Friday (AB 1054). Newsom has urged them to pass it by July 12, when the legislature adjourns for its summer recess.
The goal of such haste is to signal to credit rating agencies that the state is prepared to prop up its investor-owned utilities in the face of billions of dollars in wildfire liability. The bill includes a multibillion-dollar wildfire recovery fund that would be financed by the IOUs and a surcharge on customers’ bills. Ratepayers and utilities would each pay $10.5 billion.
Gov. Gavin Newsom wants lawmakers to pass his wildfire package by the end of this week. | Cal OES
Assemblyman Christopher Holden, a co-author of the bill and chairman of the Assembly Utilities and Energy Committee, told his Senate counterparts Monday that the measure would help “keep the lights on in order to protect customers.”
“Stable utilities are the backbone of our economy and the necessary background of our daily lives,” Holden said while presenting the bill to the Senate Energy, Utilities and Communications Committee, which passed the bill 9-2. The Senate Appropriations Committee approved it shortly afterward.
Lawmakers are under pressure to help the utilities while avoiding political blowback from any measure that could be labeled a bailout. Voter anger remains high with Pacific Gas and Electric, which has been blamed for starting massive, deadly fires in 2015, 2017 and 2018, including November’s Camp Fire, the deadliest in state history. The state’s largest utility and its parent company, PG&E Corp., filed for bankruptcy in January.
PG&E’s stock price plummeted along with its credit rating, which S&P Global Ratings now lists as “D,” its lowest mark. The price has recovered from its low point of about $6/share in January, closing at $21.73 on Monday.
Stock prices for PG&E and Southern California Edison have dropped amid uncertainly over fire liability and utilities financial stability. | Google
Southern California Edison also has been blamed for deadly fires, such as the Thomas Fire in December 2017 and the Woolsey Fire in November 2018. The Woolsey Fire and ensuing mudflows killed nearly two dozen people.
S&P rates SCE and Sempra Energy, the parent company of San Diego Gas & Electric, as BBB, an investment grade, despite concerns about the IOUs’ long-term stability. But ratings agencies have said they may downgrade the ratings if the state fails to act. Their stock prices have been less volatile than PG&E’s.
AB 1054 includes provisions intended to increase the accountability of utilities for safety. To draw from the recovery fund, the IOUs would have to link executive compensation to safety performance. The California Public Utilities Commission would have to certify a utility had acted reasonably before it could recover wildfire costs.
Testimony and comments at Monday’s hearing were largely positive, even from staunch critics of the IOUs.
Up from the Ashes, a wildfire victims’ group, said it supported the bill because it could compensate victims more quickly. And The Utility Reform Network (TURN) backed the bill, with reservations, because it requires the utilities to contribute billions of dollars to the recovery fund.
Those who opposed it included some fire victims and Sen. Scott Weiner, a San Francisco Democrat, who took issue with a provision that could make it more difficult for utilities to sell assets. San Francisco is considering a bid to purchase PG&E’s equipment and establish a municipal utility.
The legislation goes next to the State Assembly for a concurrence vote as early as Thursday. Because it is an urgency measure that would take effect immediately upon being enacted, it requires a two-thirds supermajority vote by both houses to get to Newsom’s desk.
Saying recent Texas legislation has rendered their case moot, Entergy, Southwestern Public Service and Texas Industrial Energy Consumers have asked to dismiss their appeal of a Public Utility Commission order negating an incumbent utility’s right of first refusal (03-18-00666-cv).
The parties told the Texas Third Court of Appeals in Austin on June 21 that Senate Bill 1938, passed in May, has “mooted the underlying controversy”: an appeal of a 2017 PUC ruling that SPS does not have the exclusive right to build transmission facilities in its service territory.
But Southwest Transmission and GridLiance High Plains asked the Texas court on June 27 to reject the motion to dismiss pending the resolution of a separate federal court challenge to the legislation.
The bill, which Gov. Greg Abbott signed on May 16, amended the Public Utility Regulatory Act to grant certificates of convenience and necessity (CCNs) to build, own or operate new transmission facilities that interconnect with existing facilities “only to the owner of that existing facility.” That essentially cuts out independent transmission companies from competing for projects anywhere in Texas, including for FERC Order 1000 projects in non-ERCOT areas. (See Texas ROFR Bill Passes, Awaits Governor’s Signature.)
In their filing, the parties said the Texas Legislature “has thus clarified that Texas law” gives SPS and Entergy “the exclusive right to build new transmission lines in their respective service territories.”
RTO boundaries in Texas | ERCOT
The parties also said the bill clarifies the Legislature’s intent to retain the state’s jurisdiction over retail rates in non-ERCOT areas of Texas “by effectively prohibiting the certification of new-entrant, transmission-only utilities whose rates would be subject to FERC’s exclusive jurisdiction.”
Because no transmission-only utilities currently operate in Texas’s non-ERCOT regions, the parties said, “the exclusivity provisions and limitations on transfers of certificate rights to utilities already certified within a particular power region will act as a bar to any future certification of such entities.”
Entergy, SPS and TIEC, a trade association of the state’s largest consumers, had appealed a Travis County District Court ruling that agreed with the PUC’s 2017 order (Docket 46901). The commission ruled that existing law did not give SPS a ROFR, and that it could award CCNs to transmission-only utilities in the state’s non-ERCOT regions. (See Texas Commission Rejects SPS ROFR Request.)
The PUC told the court June 27 that it was “unopposed” to the motion to dismiss.
But Southwest Transmission and GridLiance High Plains asked the court to consider staying the case pending NextEra Energy’s challenge of the constitutionality of SB 1938. (See NextEra Takes Texas to Court over ROFR Law.)
NextEra’s challenge, filed in the U.S. District Court for the Western District of Texas on June 17, alleges SB 1938 is unconstitutional because it violates the dormant Commerce Clause and the Contracts Clause.
| Wind Energy Transmission Texas
“It is entirely possible that the federal district court may decide that the PURA provisions enacted under SB 1938 are, as alleged in NextEra’s lawsuit, unconstitutional and thus invalid and unenforceable,” the companies said. “A dismissal of the [Texas] appeal at this juncture, when NextEra’s lawsuit is pending, would potentially result in a still valid trial court judgment being vacated and the need for one or more of the parties to this case to refile and pursue a new, redundant appeal of the underlying PUC decision.”
NextEra transmission subsidiaries had won a competitive bid for a MISO 500-kV project in Southeast Texas and had a CCN application pending before the PUC to assume ownership of 138-kV facilities in Northeast Texas.
A huge spike in natural gas prices drove up the cost of wholesale electricity in CAISO by more than 40% in the first quarter of 2019 compared with the same period a year ago, the ISO’s Department of Market Monitoring reported.
However, the disparity between income and payments for congestion revenue rights dramatically improved since the first quarter of 2018, lessening costs for ratepayers, the department said.
The Monitor reported the mixed first-quarter results in a July 2 web conference.
Amelia Blanke, CAISO manager of monitoring and reporting, said it cost about $2.7 billion — or $55/MWh — to serve load in the ISO’s territory during the first three months of this year. That was a 42% increase from Q1 2018.
Gas prices were 73% higher in the first three months of 2019 than they were in the first quarter of 2018, the Monitor reported. Lower temperatures, high heating demand, and supply constraints led to gas prices that more than doubled from January to February of this year.
“High natural gas prices in February 2019, at both SoCal and PG&E Citygate, were the main driver of high system marginal energy prices across the ISO footprint,” the Monitor said in its Q1 Report on Market Issues and Performance.
Gas prices in CAISO spiked in the first quarter of 2019, driving up electricity costs. | CAISO
As a result, average day-ahead electricity prices increased “by around $17/MWh (almost 50%), 15-minute by about $15/MWh (45%) and five-minute market prices by $13/MWh (35%) in comparison to the same quarter in 2018,” it said.
The Monitor noted that natural gas units are often the marginal source of generation in CAISO and the rest of the West.
The Northwest Sumas gas hub in the Pacific Northwest saw record high gas prices during the winter months of 2019.
“The price spike comes amid limited supply deliverability and unseasonably cold temperatures, which drove up demand in the Northwest,” the Monitor said. “Prices at the Sumas gas hub have been volatile since the Oct. 9, 2018, Canadian gas pipeline explosion reducing imports into hubs in the Northwest.” (See NW Price Spike a Wake-up Call,’ Ex-BPA Chief Says.)
The high gas prices were offset by increased generation from wind and hydroelectric resources.
“Compared to 2018, hydroelectric production in the first quarter increased by roughly 47%,” the report said.
The extremely wet winter in California increased snowpack to 175% of normal on April 1, compared to 58% of normal on the same date in 2018.
Compared to the first quarter of 2018, wind production increased while solar production dropped slightly, despite increased solar capacity. “This was likely due to greater curtailments resulting from high hydro and wind production,” the Monitor said. “In March 2019, renewable curtailment reached record levels, roughly 125,000 MWh.”
“The ISO became a net exporter on average during peak solar hours [noon to 3 p.m.] over the entire quarter, as imports fell and exports increased in these hours relative to prior quarters,” the Monitor added.
Closing the Gap in CRRs
The first-quarter 2019 results also suggested that changes CAISO implemented last year to CRR auctions are working.
The gap between auction revenues and payments to owners of congestion revenue rights in CAISO fell in Q1. | CAISO
The Monitor reported that income from the auctions fell short of payments to purchasers by $1.5 million in the first quarter of 2019 — a sharp drop from the $43 million difference in the first quarter of 2018.
Payments and revenues were closer to parity than in any first quarter since 2012, the Monitor reported.
Ratepayers have been covering big losses in the CRR auctions since they were implemented in 2009. The total loss is now about $860 million, the Monitor said in its report. (See CAISO Q4 CRR Revenues Falling Short After Summer Surplus.) The main beneficiaries have been financial entities that purchase the CRRs, betting on profits.
“The decrease in losses to transmission ratepayers from sales of congestion revenue rights is due in part to changes to the auction implemented by the ISO in 2019, which limit the source and sink of congestion revenue rights that can be purchased in the auction,” the Monitor said.
FERC has accepted SPP’s proposal to refine its generator interconnection procedures by instituting a three-stage study process (ER19-1579).
The RTO’s Tariff revisions adopt a three-phase process of thermal and voltage analysis, stability analysis, and facilities study. They also change the eligibility for refunds of financial security.
The commission rejected concerns from Enel Green Power and EDF Renewables that SPP did not have the staff and resources to accomplish all the revisions’ components.
“We are not persuaded to substitute our judgment for SPP’s in determining the level of staff and resources that SPP needs to implement its proposal,” the commission wrote in the June 28 order. It pointed out that the reforms might reduce redundancies and result in the “more efficient use of administrative time” that could be devoted to the new study process.
The changes include the elimination of the feasibility and preliminary queues, changes to the amount and timing of security deposits, publishing study models earlier in the process, and allowing penalty-free withdrawals when costs increase above certain thresholds. They became effective July 1.
The Tariff revisions were approved by SPP stakeholders in January following several years of development. The RTO filed its request in April. (See “Stakeholders Approve Streamlined Generator Interconnection Process,” SPP Markets & Operations Policy Committee Briefs: Jan. 15, 2019.)
3-Stage SPP Generator Interconnection Study Process | SPP
In its filing, SPP said it had more than 440 interconnection or modification requests, totaling 81 GW of new generation capacity, in its interconnection study queue.
Enel and EDF argued it was unjust and unreasonable to “subject interconnection customers to higher and potentially nonrefundable financial security and a longer queue process” if SPP was unable to efficiently handle the process studies.
FERC disagreed, saying SPP’s proposal to separate the security deposit into three payments, which are due before each of the three phases and become “further at-risk as the interconnection customer progresses through the queue … should help dissuade more speculative projects from entering later study phases, which should decrease the number of late-stage, disruptive withdrawals.”
The commission also found the security deposit’s financial outlays were not “excessive.”
“Under SPP’s design, the total financial security an interconnection customer will pay is roughly 20% of its estimated network upgrade cost responsibility, which is the total payment required for SPP’s existing initial payment,” FERC said.
Michigan regulators are calling on the state’s gas and electric utilities to step up measures to head off supply emergencies like the one that arose this past winter during a deep freeze.
While a draft report released by the Michigan Public Service Commission on July 1 determined that the state’s energy systems are adequate to meet customer needs, it also urged utilities to undertake a raft of improvements to address extreme weather events, security threats and the expanded use of renewable energy sources.
Gov. Gretchen Whitmer ordered the statewide energy assessment after a polar vortex struck the state Jan. 30-31. During the event, both Consumers Energy and DTE Energy issued public appeals for conservation, while Whitmer appeared on video via social media to ask ratepayers to lower thermostats or risk a gas shortage. Consumers’ gas scarcity was compounded by a fire at Ray Compressor Station near Detroit. (See “Gas Shortage Warnings,” MISO Maintains Reliability Through Arctic Midwest Temps.)
Consumers Energy’s Ray Compressor Station | Wallbridge
“Despite the positive outcome, the events of Jan. 30 and 31 raised significant concerns about whether Michigan’s energy systems can reliably produce and deliver energy to all Michiganders as extreme weather events increase,” the PSC said.
The agency was asked to evaluate whether the design of electric, natural gas and propane delivery systems are “adequate to account for operational problems, changing conditions and extreme weather events” (U-20464). The 231-page report makes 36 recommendations within the commission’s jurisdiction and 14 “observations” outside the scope of its jurisdiction.
Among its major recommendations, the PSC said utilities should:
Incorporate five-year-ahead distribution and transmission plans into the integrated resource plans required by the state. The commission said the move would “ensure truly integrated electricity system planning” and could expand electrical connections between Michigan’s peninsulas and neighboring states. It said an expanded ability to import electricity could address short- and long-term reliability issues.
Undertake “long-term, risk-based” natural gas infrastructure and maintenance planning. It also recommended natural gas utilities include equipment and facility outages in risk models and better plan for transmission contingencies.
Make more careful retrofitting, retirement and new power plant build decisions. The agency said utilities should work with stakeholders “to understand the value of resource supply diversity” and not rely so heavily on traditional planning and financial analyses. Utilities should “propose a methodology to quantify the value of generation diversity in integrated resource plans.”
Re-examine natural gas utility curtailment procedures to make sure they “prioritize home heating over electric generation.”
Improve electric demand response programs “since some customers did not respond as expected during the polar vortex, and utility tariffs were inconsistent.” The PSC said natural gas utilities should also work to create DR programs “as an alternative to broad emergency appeals.” Utilities should also review their communication protocols with customers during DR events.
Create rules for cybersecurity and incident reporting for natural gas utilities and improve energy system cybersecurity in general. The PSC suggested utilities undertake regular IT audits, simulated phishing campaigns, multifactor authentication for remote access and cybersecurity performance assessments.
Develop standardized communications with the commission for electric and natural gas emergency events.
Expand use of emergency drills “to provide a range of scenarios besides outage management and restoration.” The PSC said utilities should also test curtailment and DR events. “Communication related to the Ray event and the polar vortex was confusing, inconsistent and erratic,” it concluded.
Improve communications and data sharing in general between electric utilities, PSC staff and RTOs to ensure that the “RTOs will have the information needed to plan and operate the electric system to accommodate an increasing amount of distributed energy resources.”
“Overall, the energy system is strong but would benefit from increased resilience, strengthened infrastructure interconnections and improved communication,” PSC Chairman Sally Talberg said.
The PSC also found that MISO should enact a seasonal capacity auction, “more carefully consider” non-transmission alternatives prior to approving transmission projects and speed up its generator interconnection queue — although those items are outside of the regulator’s purview.
The commission also found that Michigan statue limits the PSC in assessing “meaningful penalties” for utilities that are not in compliance with the Michigan Gas Safety Standards. “This may impact the health, safety and welfare of Michigan residents,” the PSC said.
The commission formed five work groups — focusing on electricity, natural gas, propane, cyber and physical security, and energy emergency management — and hosted more than 40 internal and external meetings to create the initial report.
After a public comment period, the commission will deliver a final report to Gov. Whitmer by Sept. 13. The commission could then order utilities to take steps to improve their energy supply and delivery processes.
Consumers Energy linemen in winter | Consumers Energy
“Moving forward, this report will help to inform our next steps in assuring all Michiganders have reliable access to energy when they need it at home, at school and at work. With the transition to more renewable energy resources and the growing impact of climate change, it is imperative that our utility infrastructure can meet the changing demands while keeping rates affordable and protecting the environment,” Whitmer said in a press release.
In its latest resource adequacy survey, the Organization of MISO States identified Michigan’s Lower Peninsula as one of three MISO areas that could soon experience supply shortages, with a potential 0.9-GW shortage as early as 2020. (See Supply Future Brighter, OMS-MISO Survey Shows.)
