A recent Rice University study that suggests Texas renewable power production could become more reliable by combining different resources and locations did not surprise independent developer Mannti Cummins.
He’s been there and done that, having helped bring thePeñascal Wind Farm project in South Texas online in 2010. The 404-MW facility also happens to be one of the sites used in the Rice study.
Peñascal II wind project | Mortenson
“This kind of confirms the rustic logic of common-sense folks who don’t have the ability to do the necessary calculations and analytics,” Cummins said from Mexico, where he is working on another project in Baja California Sur. (See Energy Wildcatter Hopes to Make His Mark in Emerging Mexican Market.)
“This kind of confirms, with an academic methodology, what we’ve all thought is going to be the future,” he said.
In their study, Renewables: Wind, Water, and Solar, Rice researchers Dan Cohan and Joanna Slusarewicz analyzed data from five wind and seven solar sites across West and South Texas. Because of the state’s varying wind patterns and solar irradiance, they found that pairing solar power with either West Texas winds or South Texas winds will increase renewable power production.
West Texas winds peak during early night hours (6-10 p.m.), while South Texas winds tend to follow load patterns and peak in the late afternoon. The researchers said that pairing solar with western wind farms provides the highest levels of firm capacity with an 87.5% threshold, increasing reliable power production on an annual basis.
South Texas’ late-afternoon wind peaks suggest that combining solar with wind “might increase reliable power production over the course of a summer day during hours of high demand,” they wrote.
Cummins said the Peñascal development team in the early 2000s chose the barren scrub of South Texas because the wind peaks at the right time. “It’s just perfect with the load profile,” he said.
The Peñascal site is also situated between the Corpus Christi and Rio Grande Valley population centers, where it could take advantage of under-used transmission facilities without taking part in the state’s Competitive Renewable Energy Zones process. (The wind farm did benefit from more than $220 million in federal stimulus funds.)
“But nobody ever thought about pairing [wind] with solar,” Cummins said. “You can start talking about it because [solar is] economical.”
He said that prices for installed solar are 50% below where they were three years ago, dropping from $2,000/kW to $900/kW. Solar is crushing natural gas, Cummins said, a situation he expects to continue as battery storage becomes more commonplace.
“As the price of battery storage drops like a rock, that’s the future,” he said.
Cummins is following that concept of wind-integrated solar energy with his Coromuel project at the tip of the Baja California peninsula. The 50-MW wind facility, named for the local weather phenomenon, will include 600-kV solar panels at the foot of each turbine.
“When the wind has its own name, it’s probably consistent enough for wind generation,” he said, comparing the afternoon peak to South Texas winds.
“The rise of clean energy appears to be everywhere across Texas,” said developer John Billingsley in a statement following the Rice study’s release. Billingsley is CEO of Global Energy and also launched Sunfinity Renewable Energy three years ago.
Billingsley agrees with Rice’s Cohan, who said the research shows “nowhere else in the world [is] better positioned to operate without coal than Texas is.”
As it is, coal only accounts for 15.5 GW of ERCOT’s existing resources, with wind and solar combining to account for 22 GW. No coal projects are listed in the ISO’s latest generator interconnection report, while there are 14.3 GW of wind, 4.3 GW of solar and 2.7 GW of gas projects with signed interconnection agreements.
During a recent appearance in Houston, ERCOT CEO Bill Magness said, “It’s all gas, wind and solar. There are no other resources coming along.”
ERCOT expects to have as much as 5 GW of solar energy on the system by 2021, much of it in West Texas.
“We’ve only begun to scratch the surface in terms of truly harnessing our clean, renewable resources,” Billingsley said. “The next several years will see amazing strides forward.”
I want to begin with a note about FERC Commissioner Kevin McIntyre’s passing. He and I (and my wife) worked together for years at the law firm Reid & Priest. He was a talented attorney and an all-around great guy. Kevin, thank you for your contributions to the energy bar, to the work of the commission, and to the lives of those who have known you. You will be missed.
Four years ago, I began writing on subjects in our industry that I hoped would be of interest. Mostly heresy about conventional wisdom.
I thought it might be worthwhile to take a look back at some of those scribblings, see what I got right, what I got wrong and what’s happened since.
Reliability Standards: Reality Check
My first article[1] challenged the conventional — and intuitive — wisdom that mandatory reliability standards had improved reliability. I argued:
Mandatory reliability standards have had little apparent effect on reliability.
Relatively few outages can be avoided/mitigated by reliability standards.
Outage avoidance provides relatively little value to consumers.
Mandatory reliability standards impose costs and potential adverse consequences.
We should focus more on actual causes of outages and work backward on a true cost-benefit basis.
Since that article, NERC data suggest that transmission-related load losses have declined over the years. Its chart is below.
BPS transmission-related events resulting in load loss (excluding Criteria 4) | NERC
The apparent trend in transmission-related load loss is good. But it’s also worth pointing out that Transmission Availability Data System (TADS) outage events haven’t declined at all. There were 3,705 in 2009 and 3,790 in 2017.[2] The key reason for this, as I discussed in the article, is that the vast majority of outage events have causes beyond anyone’s control: e.g., lightning, other weather, equipment failure, foreign interference.
My basic concerns seem to remain valid. A meaningful reduction in transmission-related outages is questionable. Transmission-related outages are a small percentage of overall outages and, despite the media attention they receive, actually amount to relatively few dollars in terms of the value of lost load (VOLL). There also are compliance costs, and there can be potential adverse consequences if resource allocations are largely driven by compliance considerations.
Capital Spending Without Cost-benefit Analysis
But I think my last point from the article four years ago is the most important today. We now spend more than $20 billion on transmission infrastructure every year.[3] Each $20 billion of capital spending adds about $3 billion to consumer bills every year for decades into the future. The consumer cost keeps adding up. And virtually none of the cost is supported by cost-benefit analysis.[4]
This is not rocket science. In a competitive industry, investment is justified by the return expected to result from customer demand based on what customers are willing to pay. The parallel in a regulated industry should be investment justified by customer demand based on what customers are willing to pay.
In the electric utility industry, the proxy for customer willingness to pay must be the VOLL. In other words, every dollar of regulated utility investment should be explicitly supported by the customer VOLL that is produced by that investment. Nothing else makes sense.
Yet, cost/VOLL-benefit analysis continues to be ignored by regulators who bless $20 billion of new transmission capital costs every year.
Again, without a clue whether the cost imposed on consumers is actually worth it to consumers.
The Double and Triple Whammies
There’s a double whammy at work here. As I’ve pointed out before, regulators are allowing returns on equity vastly in excess of utilities’ true cost of capital.[5] Not only do the excessive returns burden consumers directly, but they create an enormous incentive for utilities to overspend on capital projects. You can follow the money on quarterly utility conference calls with Wall Street analysts — slides and talk about future capital spending, which drives earnings growth, which drives higher stock valuation.
There’s actually a triple whammy because the excessive returns also create an enormous incentive for utilities to fight competition in all forms, including competition in transmission. There is no doubt that competition in transmission is a staggering success (where it has been faithfully implemented), for reasons I’ve discussed before.[6] But because of excessive returns, utilities have added incentive to fight that competition by all possible means. And naturally they do.
Gotten Far Worse
This situation has, if you can believe it, gotten far worse in the past few years. It used to be that transmission capital costs would be justified for mitigation of reliability criteria violations. In other words, the transmission grid would be modeled for the future, and if the model forecasted overload of a given line, or other transmission element, then upgrade or other mitigation of the overload would be prescribed.
Nowadays, in PJM for example, most transmission capital costs are completely divorced from reliability criteria violations and instead are supported by violation of criteria unilaterally set by transmission owners. Here is a shocking chart showing this phenomenon:[7]
Cost of PJM TO’s baseline vs. supplemental projects | American Municipal Power
The dark blue is what the TOs unilaterally decide; the light blue is what is needed for reliability.
Now, you might ask: Isn’t allowing TOs to unilaterally decide the criteria for how much capital to spend, on which they get excessive allowed returns, putting the fox in charge of the henhouse? And you would be right to ask that question.
FERC has developed “transmission metrics” but none of them involves cost-benefit analysis or the Value of Lost Load. https://www.ferc.gov/legal/staff-reports/2017/transmission-investment-metrics.pdf. At least one metric, “load-weighted transmission investment,” seems to imply that more transmission spending is inherently good. ↑
Unfortunately, the most recent FERC orders on unilateral transmission owner spending will further embolden the fox. California Public Utilities Commission v. Pacific Gas and Electric Co., 164 FERC ¶ 61,161 (2018); Monongahela Power Co., 164 FERC ¶ 61,217 (2018). Somewhere along the line, the basics seem to have been lost: The utility fiduciary obligation is to shareholders to extract maximum monopoly rents from consumers. The commission’s statutory obligation is to protect consumers from this utility fiduciary obligation to shareholders. ↑
Reliability Standards, Costs and Benefits, Fox-Henhouse Regulation
By Steve Huntoon
I want to begin with a note about FERC Commissioner Kevin McIntyre’s passing. He and I (and my wife) worked together for years at the law firm Reid & Priest. He was a talented attorney and an all-around great guy. Kevin, thank you for your contributions to the energy bar, to the work of the commission, and to the lives of those who have known you. You will be missed.
Four years ago, I began writing on subjects in our industry that I hoped would be of interest. Mostly heresy about conventional wisdom.
I thought it might be worthwhile to take a look back at some of those scribblings, see what I got right, what I got wrong and what’s happened since.
Reliability Standards: Reality Check
My first article1 challenged the conventional — and intuitive — wisdom that mandatory reliability standards had improved reliability. I argued:
Mandatory reliability standards have had little apparent effect on reliability.
Relatively few outages can be avoided/mitigated by reliability standards.
Outage avoidance provides relatively little value to consumers.
Mandatory reliability standards impose costs and potential adverse consequences.
We should focus more on actual causes of outages and work backward on a true cost-benefit basis.
Since that article, NERC data suggest that transmission-related load losses have declined over the years. Its chart is below.
[insert M-2-BPS graphic here]
The apparent trend in transmission-related load loss is good. But it’s also worth pointing out that Transmission Availability Data System (TADS) outage events haven’t declined at all. There were 3,705 in 2009 and 3,790 in 2017.2 The key reason for this, as I discussed in the article, is that the vast majority of outage events have causes beyond anyone’s control: e.g., lightning, other weather, equipment failure, foreign interference.
My basic concerns seem to remain valid. A meaningful reduction in transmission-related outages is questionable. Transmission-related outages are a small percentage of overall outages and, despite the media attention they receive, actually amount to relatively few dollars in terms of the value of lost load (VOLL). There also are compliance costs, and there can be potential adverse consequences if resource allocations are largely driven by compliance considerations.
Capital Spending Without Cost-benefit Analysis
But I think my last point from the article four years ago is the most important today. We now spend more than $20 billion on transmission infrastructure every year.3 Each $20 billion of capital spending adds about $3 billion to consumer bills every year for decades into the future. The consumer cost keeps adding up. And virtually none of the cost is supported by cost-benefit analysis.4
This is not rocket science. In a competitive industry, investment is justified by the return expected to result from customer demand based on what customers are willing to pay. The parallel in a regulated industry should be investment justified by customer demand based on what customers are willing to pay.
In the electric utility industry, the proxy for customer willingness to pay must be the VOLL. In other words, every dollar of regulated utility investment should be explicitly supported by the customer VOLL that is produced by that investment. Nothing else makes sense.
Yet, cost/VOLL-benefit analysis continues to be ignored by regulators who bless $20 billion of new transmission capital costs every year.
Again, without a clue whether the cost imposed on consumers is actually worth it to consumers.
The Double and Triple Whammies
There’s a double whammy at work here. As I’ve pointed out before, regulators are allowing returns on equity vastly in excess of utilities’ true cost of capital.5 Not only do the excessive returns burden consumers directly, but they create an enormous incentive for utilities to overspend on capital projects. You can follow the money on quarterly utility conference calls with Wall Street analysts — slides and talk about future capital spending, which drives earnings growth, which drives higher stock valuation.
There’s actually a triple whammy because the excessive returns also create an enormous incentive for utilities to fight competition in all forms, including competition in transmission. There is no doubt that competition in transmission is a staggering success (where it has been faithfully implemented), for reasons I’ve discussed before.6 But because of excessive returns, utilities have added incentive to fight that competition by all possible means. And naturally they do.
Gotten Far Worse
This situation has, if you can believe it, gotten far worse in the past few years. It used to be that transmission capital costs would be justified for mitigation of reliability criteria violations. In other words, the transmission grid would be modeled for the future, and if the model forecasted overload of a given line, or other transmission element, then upgrade or other mitigation of the overload would be prescribed.
Nowadays, in PJM for example, most transmission capital costs are completely divorced from reliability criteria violations and instead are supported by violation of criteria unilaterally set by transmission owners. Here is a shocking chart showing this phenomenon:7
[insert Cost of PJM TOs graphic here]
The red is what the TOs unilaterally decide; the blue is what is needed for reliability.
Now, you might ask: Isn’t allowing TOs to unilaterally decide the criteria for how much capital to spend, on which they get excessive allowed returns, putting the fox in charge of the henhouse? And you would be right to ask that question.
FERC has developed “transmission metrics” but none of them involves cost-benefit analysis or the Value of Lost Load. https://www.ferc.gov/legal/staff-reports/2017/transmission-investment-metrics.pdf. At least one metric, “load-weighted transmission investment,” seems to imply that more transmission spending is inherently good.
Unfortunately, the most recent FERC orders on unilateral transmission owner spending will further embolden the fox. California Public Utilities Commission v. Pacific Gas and Electric Co., 164 FERC ¶ 61,161 (2018); Monongahela Power Co., 164 FERC ¶ 61,217 (2018). Somewhere along the line, the basics seem to have been lost: The utility fiduciary obligation is to shareholders to extract maximum monopoly rents from consumers. The commission’s statutory obligation is to protect consumers from this utility fiduciary obligation to shareholders.
FERC last week approved ISO-NE’s proposed values for the installed capacity requirement (ICR), Hydro-Québec interconnection capability credits and related values in time for the RTO’s Forward Capacity Auction 13 on Feb. 4.
The RTO proposed an ICR of 34,719 MW for FCA 13’s 2022/23 capacity commitment period.
The commission’s Jan. 4 order found “that the underlying system reserves assumption used to calculate the ICR-Related Values is just and reasonable” and that the filing “sufficiently supported the use of different tie benefits and outages assumptions to calculate the ICR-related values than those used in the Fuel Security Study” (ER19-291).
ISO-NE and NEPOOL together filed two sets of ICR-related values, with one set assuming FERC would accept termination of the capacity supply obligation for Invenergy’s delayed 485-MW Clear River Energy Center Unit 1 for the 2021/22 Capacity Commitment Period, which the commission did in November. (See FERC Ends Clear River CSO, Denies Invenergy Waiver.)
| ISO-NE
The commission in December approved ISO-NE’s interim proposal to use an out-of-market mechanism to address concerns about fuel security and implement an interim fuel security study process for FCA 13, 14 and 15 to establish whether a resource submitting a retirement de-list bid is needed to maintain regional fuel security. It also accepted ISO-NE’s proposal to treat resources retained for fuel security purposes as price-takers by requiring them to submit offers into the FCA at a zero price. (See ISO-NE Fuel Security Measures Approved.)
Contested Issues
Contested issues in the most recent proceeding pertained to assumptions that affect the ICR and system-wide demand curve.
The New England Power Generators Association (NEPGA), the New England States Committee on Electricity (NESCOE) and others protested various aspects of the RTO’s calculations and methodology.
But the commission disagreed “with NESCOE’s argument that the increased reserves assumption should be rejected because it exacerbates an alleged bias in ISO-NE’s ICR calculations. … As an initial matter, we are not persuaded that the cited reductions in ICRs weigh on the justness and reasonableness of the specific system reserves assumption change that ISO-NE proposes in this filing.”
The commission also found “inconsistent” with the Tariff a request by FirstLight and NEPGA that it require the grid operator to recalculate the ICR using alternative assumptions used in the fuel security study.
“We also disagree with NEPGA and FirstLight’s assertions that, because fuel security resources are entered into FCA 13 as price-takers, ISO-NE must use the same tie benefits and outages assumptions in its analyses,” said the commission.
Lastly, the commission noted its finding in the fuel security compliance order (ER18-2364) “that the current design of the Forward Capacity Market does not account for fuel security attributes in solving for the resource adequacy problem, which creates the need for a separate Fuel Security Study process in the interim. However, the commission also reaffirmed in that order its support for market solutions as the most efficient means to provide reliable electric service to New England consumers at just and reasonable rates.”
CARMEL, Ind. — With less than a month remaining until MISO files Tariff changes to implement stricter requirements for outage notification, stakeholders last week offered alternatives that would soften the RTO’s proposal.
While talk at the Jan. 3 Reliability Subcommittee meeting was less contentious than in late 2018, several stakeholders still think MISO should file rules that are less punitive and allow for exemptions and more nuance in outage types. (See MISO, Stakeholders at Odds over Resource Availability Filings.)
The proposed outage rules represent the last piece of MISO’s short-term resource availability and need proposal, which has been divided into three FERC filings. While the RTO already made two filings that will require load-modifying resources (LMRs) to produce seasonal availability documentation (ER19-650) and subject demand response to annual capability testing (ER19-651), it has yet to file changes that will improve generator outage coordination, which it plans for no later than Jan. 31. (See “Stopgap Filings,” MISO to Address Growing Supply Shortage in New Year.) MISO hopes to implement the rules in time to cover at least part of the spring outage season.
The RTO has proposed that planned outages must be scheduled at least 120 days prior to the scheduled outage start date, avoiding “high risk” times. The plan would allow limited adjustments to an outage schedule — not to exceed seven days — 60 days prior to a start date. Planned outages scheduled or modified outside of those timeframes — and that occur during defined “high-risk” times where maximum generation conditions occur — would be categorized as forced outages, which count against a resource’s capacity accreditation. Resources would be allowed only one planned outage per 120-day period.
MISO has pledged to provide market participants with forecasts showing high-risk times on a subregional basis.
MISO Director of Resource Adequacy Coordination Laura Rauch said the goal of the filing is to encourage more forward scheduling of outages so the RTO can better prepare for any reliability risks.
But some stakeholders say that MISO’s forecasts are not accurate enough to define such periods of high risk to the system. They also contend that MISO should better define high-risk predictions, outage reporting requirements and penalties.
“I won’t pretend that we have unanimous consensus on this,” Rauch said.
Rauch said MISO will continue to work on how it can improve its Maintenance Margin, a nonpublic member webpage that keeps a forward account of how many megawatts can be taken out of service without affecting reliability.
Rauch said MISO is now focusing on whether it should provide incentives for generators that willingly move outages to improve reliability at the RTO’s request. MISO is also examining how it can best collect information to gauge how flexible a certain generator’s outage might be.
Exemptions and Outage Distinctions
DTE Energy submitted an alternate proposal that would allow a distinction between advance notice planned outages and short-term maintenance outages, which last two weeks or less and are more minor in nature and more flexible than periodic planned outages.
DTE also recommends that MISO under some circumstances exempt resources from a forced outage penalty for outages that occur during capacity emergency conditions. One exemption would permit resources to schedule planned outages even during high-risk periods if they provide four months’ notice; the other would allow for short-term maintenance outages scheduled at least seven days in advance and “entirely above” a MISO-defined scheduling margin, which would rely on a version of the Maintenance Margin process.
Xcel Energy’s Kari Hassler said her company supports DTE’s suggested tiered approach with exemptions and added that MISO should allow outages to be scheduled according to availability shown on the Maintenance Margin. She said a resource qualifying for an exemption should be allowed to revise outage stop and start times and durations “at any time as long as the shift maintains or improves the Maintenance Margin.”
Hassler also contended that MISO should allow more than one planned outage per 120-day period if the outages are taken for different reasons, saying a small testing outage can portend a major planned outage. She also urged MISO to have more faith in the motivations of generation operators.
“I think for the most part, generator owners and operators want to do the right thing. They want to schedule outages during low-risk periods. Generator owners and operators are not gaming the system. They want to get this right just as much as MISO does,” Hassler said.
Ameren’s Jeff Moore said although his company supports MISO’s push for better outage coordination and transparency, the proposal should contain some allowances for shorter-term maintenance outages.
“We do have to have this to properly maintain our assets,” he said.
Moore noted there are “legitimate reasons” for having more than one outage in a four-month timeframe and that resources should not be penalized for adjusting the timing of major planned outages as long as there is adequate headroom in the Maintenance Margin.
Several stakeholders also offered the idea that MISO delay a Tariff filing altogether in favor of providing market participants with more upcoming outage data and high-risk period predictions. They said MISO might see a natural improvement in outage coordination as generation operators gain more access to forward-looking data.
“Let’s see how this works for a year. If it works well, we may not need penalties. Nobody is suggesting that generation owners have been playing games up until now,” said Bill Booth of the Mississippi Public Service Commission.
Rauch responded that MISO has been furnishing the Maintenance Margin tool for several years, but it remains underused. She also said the RTO still needs more information about generator owners’ outage plans to manage increasing emergency conditions.
Rauch said MISO staff will scrutinize its proposed notification times and rescheduling requirements and modify the proposal over the next week. The RTO has planned a conference call to review final Tariff language with stakeholders on Jan. 14.
FERC on Friday accepted NYISO’s compliance filing for Order 844, which directs each RTO/ISO to establish procedures for reporting uplift payments, operator-initiated commitments and transmission constraint penalty factors.
The commission’s Jan. 4 order found the ISO’s filing “complies with Order No. 844’s requirements regarding zonal uplift reporting,” although approval is subject to the ISO specifying the effective date for its proposed Tariff revisions at least two weeks in advance of that date (ER18-2400).
Uplift costs from guarantee payments by category and region, Q3 2018 | Potomac Economics
FERC’s ruling granted NYISO an extension permitting Tariff revisions related to the zonal uplift and resource-specific uplift reports to become effective March 15, while those related to operator-initiated commitment reporting will become effective “on a flexible effective date between June 1, 2019, and June 20, 2019, subject to a compliance filing.”
The commission accepted the ISO’s argument that it already complies with Order 844’s requirement that its Tariff include transmission constraint penalty factor practices.
Order 844 stipulates that each RTO/ISO post a monthly report of all uplift payments categorized by transmission zone, day, and category. RTOs also must post a monthly resource-specific report containing resource names and total amounts of uplift paid in dollars, aggregated across the month.
The grid operators are further required to post a monthly report listing the commitment size, transmission zone, commitment reason and commitment start time of each operator-initiated commitment.
NYISO agreed to comply with all the requirements, modifying its compliance filing to incorporate reporting of uplift paid to suppliers that schedule import transactions at any of its external proxy generator buses as part of the zonal uplift report. The ISO said it does not pay uplift to entities that schedule export transactions and will post an updated zonal uplift report when it first posts its resource-specific uplift report to ensure the two reports are using consistent data sets.
Massachusetts electricity suppliers won’t have any trouble this year meeting the state’s new mandate for serving a certain portion of their sales with “clean peak” resources.
That’s because the state’s Department of Energy Resources (DOER) last week set the 2019 minimum to zero while it attempts to work out the details of the Clean Peak Minimum Standard.
“After reviewing available information, the statutory definition of clean peak resources, and a number of other factors, DOER determined that approximately 0 MWh were being served by existing clean peak resources during peak load hours as of December 31, 2018, and established the Minimum Standard percentage requirement for retail electricity suppliers in the 2019 compliance year at 0%,” Director Michael Judge said in a Dec. 31 email to industry stakeholders.
Passed into law last September (H4857), the standard requires DOER to mandate that a baseline minimum percentage of retail electricity sales be met with clean generation resources or load reductions during seasonal peak periods.
Under the law, clean peak resources include qualified renewable portfolio standard and energy storage resources, with an in-service date on or after Jan. 1, 2019, but no such resources could have existed as of Dec. 31, 2018. Demand response resources can also qualify without any specified in-service date, but DOER has yet to establish the eligibility requirements for DR.
The rule is also designed to build on previous performance, with every electricity retailer in the state required to provide a minimum of an additional 0.25% of annual sales with clean peak certificates. But that baseline hasn’t been established yet, nor have any clean peak certificates that would allow for compliance.
In his email, Judge told stakeholders his agency will take the similar tack to how it established the state’s RPS program in 2002.
“At that time, DOER established an ‘early compliance year’ for calendar year 2002, in which the Minimum Standard percentage requirement was established as 0%, but allowed certificates to be generated, purchased, and settled at NEPOOL GIS by retail electricity suppliers for use towards requirements in subsequent calendar years,” Judge wrote. “This allowed the market to commence, but delayed actual compliance filings from retail electricity suppliers by one year.”
ISO-NE generation mix, winter 2017-2018 | Massachusetts Department of Energy Resources
Defining Peak Hours
The idea behind the clean peak standard is to reduce high-cost peak hours and incentivize renewable energy generation to be available to meet winter and summer peaks without emissions. (See New England Clean Energy Legislative Roundup.)
The DOER plans to begin designing the Clean Peak Energy Standard this month, starting with questions for stakeholders that will be posted on the Clean Peak Standard webpage. Following review, the agency will release a detailed straw proposal and solicit comments prior to filing a draft regulation.
The law defines a “clean peak certificate” as “a credit received for each megawatt hour of energy or energy reserves provided during a seasonal peak period that represents a compliance mechanism.”
“Seasonal peak periods” are the daily time windows during any of the four seasons when the net demand of electricity is the highest. Those periods would be no less than one hour and no longer than four hours in any season, as determined by the DOER.
In addition, a qualified RPS resource may generate both a clean peak certificate and a renewable energy certificate under section 11F for electricity generated and delivered to the electric grid during a seasonal peak period.
The stakeholder process is intended to help state regulators establish seasonal peak periods and the methodology for setting clean peak certificate values. Electric service providers may eventually procure such certificates from clean peak resources and enter into long-term contracts, subject to approval by the state’s Department of Public Utilities.
The DOER will also establish a minimum percentage of clean peak certificates to be derived from demand response resources, an alternative compliance mechanism for retailers and procedures for each electricity supplier to demonstrate compliance.
ISO-NE generation mix (2016) | Massachusetts Department of Energy Resources
Comprehensive Energy Plan
The state Comprehensive Energy Plan (CEP) published last month says increased electrification in the transportation and thermal sectors may increase electric load — and peak load, depending on the timing of energy use, especially the charging of energy storage and electric vehicles.
The clean peak standard and technologies such as storage that shift peak flatten this load, “especially as load shifts due to increased EVs, heat pumps, and behind-the-meter solar,” the plan said. “Flattened load enables generators to run at more efficient heat rates, reducing costs and emissions. Further, it reduces the need for future investments in transmission and distribution infrastructure, helping to lower costs of implementing future policies.”
At a public forum last summer, Asa Hopkins of Synapse Energy Economics, a consultant on the CEP said, “Once those clean peak resources are there, it’s not like they’re only there on the peak day; they also run all the rest of the time around the year and are impacting what’s going on with dispatch of different resources.” (See Massachusetts Seeks Input on Energy Plans.)
Demand for natural gas on a peak winter day forces the electric sector to rely on LNG or other stored fuels such as oil for generation, which puts the region at risk for price spikes and emission increases during extended cold weather events, the CEP said. (See ISO-NE Fuel Security Measures Approved.)
The future of Pacific Gas and Electric is in doubt as the new year begins.
Two months after the Camp Fire — the deadliest wildfire in California history — flared Nov. 8, the utility is facing intense scrutiny from state lawmakers, regulators and a federal judge who is overseeing its probation for the 2010 San Bruno gas line explosion.
Lawsuits have proliferated, blaming PG&E for the Camp Fire, and the company is facing billions of dollars in damages for that blaze and the devastating wine country fires of October 2017.
President Trump and California Gov. Jerry Brown toured the scene of the Camp Fire on Saturday, Nov. 17. Trump called it “total devastation.” | California Governor’s Office
PG&E’s stock price has plummeted by half since the Camp Fire and by two-thirds since the wine country fires, fueling speculation about its solvency. (See Destructive Fire Drives Down PG&E Stock.)
And in recent weeks, state authorities, including the California Public Utilities Commission, have publicly questioned whether the company should be broken up or have its leadership replaced. (See Camp Fire Prompts Talk of PG&EBailout of Breakup.)
State Sen. Bill Dodd, a Napa Valley Democrat and one of the authors of a 2018 law, SB 901, that allowed PG&E and other utilities to issue long-term bonds to pay for wildfire liability, said the company needs a major shake-up, starting at the top. Dodd said he was reacting to a Dec. 14 CPUC report that alleged PG&E had falsified safety records for underground gas lines.
“PG&E has demonstrated a pattern of poor management and illegal conduct that has shattered lives across California,” Dodd said in a December statement. “This latest revelation underscores the need for systematic change, which must include change on the board of directors and in the executive suite.”
The senator told RTO Insider Friday that he wouldn’t rule out breaking up PG&E into separate gas and electric divisions. “Everything should be on the table,” he said.
On Friday, NPR reported that even PG&E is considering selling off its gas business to cope with staggering wildfire costs. The report relied on unnamed sources. The utility told NPR it was “reviewing structural options” but did not specifically address the sale of any assets.
PG&E said in a news release Friday that it is engaged in a “board refreshment process” and seeking to recruit new board members with expertise in safety. The utility also said it has “formed a special Board committee that is engaging independent experts to advise on best practices in wildfire safety.” The moves respond to criticism from lawmakers and regulators who have said PG&E needs new leaders to help it cure a flawed safety culture that precipitated two years of catastrophic wildfires.
November’s Camp Fire killed 86 residents in Butte County, destroyed nearly 14,000 homes and leveled the town of Paradise, Calif., population 27,000, in a matter of hours. It followed the wine country fires of 2017, for which PG&E has been partially blamed by state fire investigators, as well as the massive gas explosion in San Bruno, Calif., that killed eight and led to PG&E’s conviction on felony charges. PG&E’s problems continued over the holidays, when Judge William Alsup, with the federal district court in San Francisco, asked the state attorney general’s office to advise him on “the extent to which, if at all, the reckless operation or maintenance of PG&E power lines would constitute a crime under California law.”
The AG responded three days after Christmas with a rundown of the charges PG&E could potentially face, ranging from misdemeanors to murder, should it be deemed to have acted recklessly.
Alsup also required PG&E to provide a thorough account of its role in the Camp Fire and the wine country fires of October 2017. PG&E answered with a detailed description of the problems it experienced with its transmission and distribution lines near the Camp Fire’s point of origin on the morning the fire started and said multiple employees had seen the fire start. (See PG&E Grapples with Line Safety After Camp Fire.)
On Thursday, the judge ordered PG&E to submit more information concerning the Atlas Fire, one of 21 major fires that started Oct. 8, 2017, and burned through large swaths of Napa, Sonoma and neighboring counties. The wine country fires killed 44 people and leveled the northern portion of the city of Santa Rosa, Calif. (The case is No. 3:14-cr—00175-WHA in the U.S. District Court for the Northern District of California.)
“PG&E’s most important responsibility is the safety of the customers and communities we serve,” the utility told RTO Insider in an email Friday. “The cause of the Camp Fire is still under investigation. We are aware of lawsuits regarding the Camp Fire. Our focus continues to be on assessing infrastructure to further enhance safety and helping our customers recover and rebuild.”
Here’s a rundown of where PG&E stands at the start of 2019.
The Tubbs Fire in California’s wine country wiped out the Coffey Park neighborhood of Santa Rosa. | California National Guard
Criminal Charges
Pacific Gas and Electric is no stranger to criminal charges in cases involving its equipment.
In June 1997, jurors in Nevada County, Calif., found the company guilty of 739 counts of criminal negligence for failing to trim trees near its power lines and sparking the Trauner Fire, which destroyed 12 homes and burned a historic schoolhouse near the Sierra foothills town of Rough and Ready in 1994.
In the San Bruno case, jurors found the company guilty in August 2016 of five felony counts of knowingly violating federal safety regulations by failing to inspect and test its pipelines and one count of obstructing a National Transportation Safety Board proceeding.
In January 2017, U.S. District Court Judge Thelton Henderson slapped the company with the maximum $3 million fine and ordered it to serve five years of probation, saying PG&E’s crimes posed “a great risk to the public safety.” (That was on top of $1.6 billion in fines levied by the state.) The company was placed under a federal monitor.
The probation from the San Bruno sentence is the basis for Alsup’s current inquiries, which began just after Thanksgiving. Under its terms, PG&E must not commit any federal, state or local crimes. Doing so could subject the company to further penalties, and its probation could be revoked, federal prosecutors told Alsup.
There is already some evidence that criminal charges are possible.
A section of the 30-foot gas pipeline owned by PG&E that exploded in 2010, killing eight people in San Bruno, Calif.
Investigators with the California Department of Forestry and Fire Protection (Cal Fire) have said PG&E equipment was to blame for at least 17 of the wine country fires. Cal Fire forwarded 12 of those cases to county prosecutors, who retain discretion about whether to charge PG&E. So far, no charges have been filed.
The AG’s office said in its brief that it wasn’t making any factual findings on whether PG&E committed crimes.
“Determining PG&E’s potential criminal liability, if any, for recent wildfires would require an investigation into the cause or causes of those fires,” the attorney general’s brief said. “If PG&E caused any of the fires, the investigation would have to expand into PG&E’s operations, maintenance and safety practices to determine whether criminal states were violated with the requisite mental intent.”
That mental intent would be measured on a sliding scale from mere negligence to reckless behavior that could constitute manslaughter or implied-malice murder, it said.
Lawsuits
Multiple lawsuits — about a half-dozen, according to various news reports — have already been filed against PG&E by survivors and insurance companies for what could add up to $15 billion in damages for the Camp Fire, according to one Citigroup estimate. That comes on top of another $15 billion in damages for many of the wine country fires, Citigroup said.
Allstate, State Farm and USAA filed suits last month in state court in Sacramento over billions of dollars in claims they expect to pay from the Camp Fire, The Sacramento Bee reported Thursday.
In another suit, filed by a prominent San Francisco plaintiffs’ firm, Lieff Cabraser Heimann & Bernstein, two children of Ernie Foss, a disabled man killed while trying to escape the Camp Fire, claim the blaze was started by “unsafe electrical infrastructure owned, operated and (improperly) maintained by PG&E Corporation and Pacific Gas & Electric Company.”
“The catastrophic damage and loss of life was preventable,” the lawsuit alleges. “PG&E’s failing infrastructure and its inadequate efforts to maintain its equipment and mitigate risk have caused tragedy before, and PG&E has been sanctioned a number of times for virtually identical misconduct.”
The complaint cites other instances in which PG&E was fined or held criminally liable for deadly fires and explosions, including the Trauner Fire, the San Bruno explosion and a fatal gas explosion near Sacramento in 2008.
“PG&E’s corporate policy of putting profits over public safety has resulted in catastrophic loss of life and injury to persons and property, including the tragic and unnecessary death of Ernie Foss,” the suit contends.
The Lieff Cabraser suit is likely just the start; other law firms have been busy signing up clients in Butte County.
The wine country suits, also called the North Bay California Fire Cases, have been consolidated under a single judge in San Francisco Superior Court and are slowly working their way toward a trial or settlement. The same will likely happen with the Camp Fire claims.
Regulators and Lawmakers
In early December, CPUC President Michael Picker said state regulators would expand their investigation of PG&E’s safety practices after the Camp Fire. (See CPUC Expands Probe Into PG&E Practices After Deadly Fire.) The investigation began in the wake of the San Bruno explosion.
On Dec. 21 the commission released a scoping memo and ruling regarding the investigation that asked whether the company’s management should be replaced, whether members of its board of directors should resign, and whether the company should be broken up into separate gas and electric divisions.
“PG&E has had serious safety problems with both its gas and electric operations for many years,” it said, citing a long list of disasters and problems for which PG&E had been penalized.
“The future of PG&E may also be impacted by other actors beyond the Commission,” the CPUC noted. “The Legislature, the court appointed Federal Monitor, the various courts considering claims against PG&E, the Federal Energy Regulatory Commission, and the communities served by PG&E all have a role in determining PG&E’s future.”
With the state Legislature returning Monday (Jan. 7), lawmakers will have to determine if legislation is needed to help keep PG&E solvent — for instance, by extending the bond provisions of SB 901 to 2018 fires — or whether the company should be reconfigured after a series of catastrophes that has grown unacceptable, even to many centrist lawmakers. (See California Wildfire Bill Goes to Governor.)
Dodd, for one, said it will be hard for PG&E to make amends, regardless of its legal compliance and restitution to fire victims.
“It’s too little, too late,” the senator said. With so much frustration and anger built up against PG&E, it may be time for the utility to face more serious consequences.
“I’m not sure there’s anything they can do,” he said.
A group representing MISO power producers filed a complaint with FERC on Monday alleging that the RTO is improperly accounting for the deliverability of some capacity resources, driving down payments to those demonstrably positioned to deliver on their obligations.
The Coalition of Midwest Power Producers (COMPP) urged FERC to force MISO to properly account for deliverability of capacity resources before the annual capacity auction in April in order to safeguard reliability (EL19-28).
MISO control room | MISO
COMPP said MISO’s loss-of-load expectation (LOLE) study process is flawed because it assumes that all capacity resources are fully deliverable on an installed capacity (ICAP) basis. However, the group argued, MISO’s megawatt count from deliverable resources comes up short annually because the RTO allows certain resources to demonstrate deliverability only up to the unforced capacity (UCAP) level.
MISO’s Tariff requires capacity resources to demonstrate either network resource interconnection service (NRIS) or energy resource interconnection service (ERIS) coupled with firm transmission service up to each resource’s ICAP level. While the RTO already requires that all resources be deliverable to load to qualify as capacity resources, its deliverability requirements stipulate that ERIS resources must only secure firm transmission for their UCAP values, which tend to be about 5 to 10% below full ICAP levels.
The discrepancy amounts to a Tariff violation and risks MISO’s adherence to its own planning reserve margin, COMPP said.
“By failing to ensure deliverability on an ICAP basis for all capacity resources, MISO is acting contrary to the assumptions of its LOLE study and failing to procure enough fully deliverable resources needed to meet its [planning reserve margin] as its Tariff requires,” COMPP said.
“The seriousness of this issue is evident in the historically low reserve margins that MISO is experiencing,” COMPP said. “Requiring compliance with the Tariff for the upcoming [Planning Resource Auction] is essential both to maintaining reliability and to ensuring rates are just and reasonable and not unduly discriminatory. Yet, despite the gravity of the situation, the RTO is proceeding in a manner that will continue to improperly count approximately 1,400 MW of undeliverable generation toward satisfying its reliability requirement.”
MISO’s Independent Market Monitor last year also advised the RTO to require a planning resource’s ICAP be deliverable over the network regardless of which interconnection service it uses. (See MISO Concurs with Monitor Ideas, Pledges More Study.) The Monitor found it problematic that MISO’s LOLE study assumes all ICAP megawatts are deliverable when they’re not.
It later pointed out that during past PRAs, as much as 1,400 MW in capacity may not have been capable of delivering to load. At the time, MISO said it would work on rule changes in time for the 2020/21 PRA.
For COMPP, those changes won’t come soon enough. The group pointed out the problem is poised to recur in the upcoming 2019/20 PRA “despite the IMM having recommended that MISO fix it for the past two auctions.” It also maintains that swings even smaller than 1,400 MW “can lead to material differences in the clearing price that fails to send accurate price signals for entry and exit.”
COMPP said that despite MISO’s apparent agreement with the Monitor, it contended that the RTO has designated the issue a low priority by “only targeting to correct its failure” for the 2020/21 PRA.
“Leaving this problem unaddressed for another day fails to abide with [Federal Power Act Section] 206’s requirements and should be deemed unacceptable by the commission. … The lack of urgency on this issue is particularly galling given MISO’s focus on dealing with current reliability issues that have resulted in some 19 emergency actions since the start of the 2016/2017 planning year,” COMPP said.
The organization also requested fast-track treatment from FERC.
MISO said it was in the process of reviewing the complaint.
ERCOT enters 2019 with a major coal plant going into mothballs and two aging gas units set for decommissioning.
After burning the last load of coal at its J.T. Deely plant on New Year’s Eve, San Antonio utility CPS Energy is now in the process of mothballing the two units, which date back to 1977 and 1978.
CPS Energy’s J.T. Deely plant | CPS Energy
The municipal utility in 2011 said it would retire Deely by the end of 2018, 15 years ahead of schedule, thus avoiding millions in environmental retrofit costs. It notified ERCOT of its plans to mothball the plant in 2013, but it must submit a notification of change of generation resource designation (NCGRD) before officially retiring and decommissioning the units.
CPS spokesperson Trace Levos said the utility plans to begin razing the plant in 2025, but utility officials are also pondering converting Deely into a gas-fired plant.
ERCOT spokesperson Leslie Sopko said the grid operator will not have to conduct another reliability-must-run study whenever CPS is ready to retire the units, as the ISO already considers the units to be unavailable.
Deely’s two coal units have a combined capacity of 871 MW. Along with Luminant’s shuttering of three coals plants in late 2017, ERCOT will have seen slightly more than 5 GW of coal-fired capacity shut down over a year. (See ERCOT OKs Luminant Coal Retirements.)
The Texas grid operator survived record-breaking demand last summer without resorting to emergency measures. It is expected to enter this summer with a historically low reserve margin of 8.1%, almost three points lower than last year. (See ERCOT Faces Tight Summer Margins, Market Changes.)
Meanwhile, NRG Texas on Dec. 28 submitted an NCGRD to ERCOT, saying it intends to decommission and permanently retire two previously mothballed gas units at its SR Bertron plant near Houston, effective Jan. 23.
The Eisenhower-era units each have a capacity of 230 MW. They were shut down for economic reasons in 2011.
