DTE Energy’s earnings fell last quarter despite gains for its electric business, the company said Monday during a call highlighting its recent push to reach zero carbon emissions by 2050.
The company reported third-quarter profits of $319 million ($1.73/share) compared with the $334 million ($1.84/share) a year earlier. Operating income fell 9 cents short of Zacks’ estimates of $2/share. DTE attributed the decline to expenses related to restoration activities after severe storms.
DTE Pinnebog wind park in the Michigan thumb region. | DTE Energy
Despite the performance, DTE increased its 2019 operating earnings guidance range from $6.02-$6.38/share to $6.06-$6.40/share.
Speaking to analysts on an Oct. 28 earnings call, CEO Jerry Norcia said 2019 “is shaping up to be a strong year as evidenced by our guidance increase.”
Chief Financial Officer Peter Oleksiak said DTE’s standalone electric earnings were $307 million for the quarter, $3 million higher than 2018, “largely due to the impact of new rates implemented in May, offset by rate base growth costs and cooler weather in 2019.”
“As a reminder, the third quarter of 2018 was one of the hottest quarters on record in our region,” Oleksiak said.
The call also focused on DTE’s recent decarbonization goal.
The company last month announced it was setting a “bold new goal” of net zero carbon emissions in its electric generation fleet by 2050. The utility had previously committed to reducing greenhouse gas emissions from electric generation by 50% from 2005 levels by 2030, 75% by 2040 and 80% by 2050.
“DTE Electric’s medium- and long-term plans aligned with the scientific consensus around the importance of achieving carbon emission reductions. We are fully committed to dramatically reduce carbon emissions. This is the right thing to do for our customers, our business and the environment. We are doing as much as we can, as fast as we can, to provide our customers and the state of Michigan with clean energy that is affordable and reliable,” Norcia said.
DTE’s new carbon reduction goals. | DTE Energy
DTE says reaching zero emissions will depend on retirement of its coal fleet, “thousands” of additional wind and solar megawatts, natural gas-fired generation and investments in carbon capture, large-scale storage and modular nuclear facilities.
The announcement comes as the Michigan Public Service Commission deliberates on DTE’s latest 15-year integrated resource plan, filed in spring. Environmentalists and renewable advocates have derided the plan as relying blindly on coal and natural gas resources and not including enough renewable energy. Multiple intervenors have urged the PSC to reject the plan. (See DTEIRP Draws Fire from Renewable Proponents.)
Norcia said progress continues on the $1 billion, 1,150-MW gas-fired Blue Water Energy Center to replace about 2,000 MW of retiring coal plants in southwestern Michigan.
“We broke ground last year and received all the necessary permits. The plant is a little over 30% complete with the turbines already on site and an expected in-service date of the spring of 2022,” Norcia said.
Norcia also reported progress on MIGreenPower, the company’s voluntary renewable energy program, saying commercial customers including Ford, General Motors, the University of Michigan and the Detroit Zoo have committed to using a combined 400 MWs of renewable power to date. Additionally, nearly 10,000 residential customers have “committed to a portion of their monthly bills [going] to renewable power,” he said.
DTE also reported the Michigan PSC last quarter conditionally approved its purchase of three new wind farms with a collective 455 MW in capacity, increasing the company’s renewables portfolio by nearly 50%. The wind farms are slated to come online at the end of 2020.
Pacific Gas and Electric’s stock price fell to a record low Monday as a huge wildfire its equipment is suspected of starting last week continued burning mostly uncontrolled in Sonoma County, Calif., amid mass evacuations and power shutoffs to 940,000 customers in Northern and Central California.
PG&E began restoring power Monday to some of its customers as winds died down, but additional public safety power shutoffs (PSPS) are expected Tuesday and Wednesday as another weather system with high winds descends on the utility’s service territory. It would be the third such event in the past week.
By Monday morning, the Kincade Fire, in the hills above Sonoma County wine country, had grown to more than 66,000 acres, with only 5% containment, as thousands of firefighters battled the blaze. It had destroyed nearly 100 structures while threatening 71,000 more, state fire officials said. No deaths have been reported as of press time.
The Kincade fire had burned more than 66,000 acres in Sonoma County as of Monday morning and forced the evacuation of 180,000 residents. | Sonoma County
The fire started Wednesday night, possibly beneath a PG&E transmission line. The line had remained energized in keeping with the utility’s PSPS protocol, PG&E said.
“Those transmission lines were not de-energized because forecast weather conditions, particularly wind speeds, did not trigger the PSPS protocol,” PG&E said in a news release. “The wind speeds of concern for transmission lines are higher than those for distribution.”
PG&E filed a report with the California Public Utilities Commission on Thursday detailing the incident beneath a line that transmits electricity from The Geysers, a sprawling geothermal field about 70 miles north of San Francisco.
About 9:20 p.m. PT Wednesday, “PG&E became aware of a transmission-level outage on the Geysers #9 Lakeville 230-kV line, when the line relayed and did not reclose,” the report said. “At approximately [7:30 a.m.] on Oct. 24 … a responding PG&E troubleman patrolling the … line observed that Cal Fire [the California Department of Forestry and Fire Protection] had taped off the area around the base of transmission tower 001/006. On-site Cal Fire personnel brought to the troubleman’s attention what appeared to be a broken jumper on the same tower.”
In a press conference Thursday, PG&E CEO Bill Johnson said, “A jumper is simply a piece of wire that jumps the conductor over the insulator.”
“Filing the [electric incident report] does not tell us where the fire started,” Johnson said. Cal Fire and PG&E are continuing to investigate, he said.
The transmission tower in question was inspected earlier this year as part of PG&E’s Wildfire Safety Inspection Program, the utility said in its statement.
A fire-detection camera reportedly caught the ignition’s fireball on a video posted by the Nevada Seismological Laboratory at the University of Nevada, Reno, which operates fire cameras in California. Footage from a news helicopter showed the tower Friday, according to a Sacramento television station.
Approximately 180,000 people were ordered to evacuate from Sonoma and Napa counties. The mandatory evacuation orders covered areas heavily damaged by the wine country fires of October 2017, including northern portions of the city of Santa Rosa that were leveled in those firestorms.
Cal Fire investigators blamed PG&E equipment for 21 of the 22 wine country fires, also called the North Bay fires, and determined that a broken PG&E transmission line sparked November’s Camp Fire, the deadliest in state history. That fire burned much of the town of Paradise, killing 86 residents and destroying more than 14,000 homes.
PG&E sought bankruptcy protection in January, citing $30 billion in liability from the 2017/18 fires.
‘Zero Share Price’
After PG&E filed its report with the CPUC last week, a Citigroup analyst warned that PG&E’s stock price could become worthless, according to MarketWatch.
“Shareholders are worried. And should be,” Praful Mehta wrote in a note to clients, the Wall Street publication said. “Kincade increases the probability of a zero share price.”
After PG&E said it would file for bankruptcy in January, its stock price hit a record low of $6.36/share. By Monday morning, a selloff of PG&E stock had dropped the price to $3.62/share. It stood at $3.80/share at the close of trading Monday.
The Wall Street Journalreported Monday that PG&E’s bond prices had also fallen, wiping out hundreds of millions of dollars on paper for its noteholders.
For weeks now, PG&E’s bondholders and shareholders have been engaged in a battle for control of the company in proceedings before Judge Dennis Montali of the U.S. Bankruptcy Court in San Francisco.
The bondholders convinced Montali on Oct. 9 to end PG&E’s period of exclusivity — the time it had to promote its own reorganization plan without interference — and to admit their Chapter 11 reorganization plan as a competitor. (See related story, Attorneys Clash over PG&E Reorg, Blackouts Resume.)
The bondholder plan would wipe out almost all existing equity in the company “because they’re issuing themselves and the victims [of 2017/18 wildfires] about 99.99% of the company,” Mehta told Bloomberg in a videotaped interview. PG&E’s plan could result in stock price of about $20 to $25/share, he said.
Mehta said he thinks it’s far more likely the judge will adopt the bondholders’ plan, which promises to inject more than $29 billion into PG&E in exchange for a controlling interesting in California’s largest utility. Mehta said he gave the bondholder plan about a 75% chance of success, versus a 25% chance for PG&E’s plan.
“So that is the 75% probability of a zero” value share price, Mehta said.
Last month, FERC Considering Tx Line Rating Rules.[/efn_note]. It’s akin to other no-brainers like LED lighting, energy efficiency standards, rational forest management, less red meat, keeping economic nuclear plants (here and abroad) and a carbon tax (aka “carbon dividends”).
This particular measure is dynamic/ambient transmission line ratings. It surfaces every 10 years or so and, sadly, nothing much gets done.[efn_note]For example, the first CAT-1 Transmission Line Monitoring System was installed in Virginia in 1991. http://sgemfinalreport.fi/files/D5.1.55%20-%20Dynamic%20line%20rating.pdf (page 20).[/efn_note]
No, it’s not glamorous like giant offshore wind turbines, huge batteries and cross-country HVDC transmission lines, and maybe that’s the problem. Fingers crossed that this conference will be a breakthrough.
Here’s the thing in a nutshell: In most of the country, transmission circuits are given a static (fixed) maximum capacity rating based on worst-case assumptions about temperature and wind speed. Of course, virtually none of the time are worst-case assumptions reflective of actual temperature and wind speed.
It’s like having a national speed limit of 25 mph because it snows occasionally. Yes, it’s that simple.
Studies and actual experience show that dynamic/ambient ratings are 30% or more than static ratings.[efn_note]Thirty percent was the low end of the ranges in the U.S. Department of Energy’s report on the New York Power Authority and Oncor projects. https://www.smartgrid.gov/files/SGDP_Transmission_DLR_Topical_Report_04-25-14_FINAL.pdf (page vi). These results were consistent with testimony at the conference, such as the Ampacimon presentation and at Tr. 34.[/efn_note] The value proposition is illustrated in the chart below from a U.S. Department of Energy study.[efn_note]https://www.smartgrid.gov/files/SGDP_Transmission_DLR_Topical_Report_04-25-14_FINAL.pdf, pdf page 103.[/efn_note] Our grid has an enormous amount of capacity that is wasted because it is not measured.
NRT-based ambient-adjusted rating and static rating probability distribution (Temple Pecan Creek-Temple Switch, September 2011) | Oncor
This causes needless congestion, curtailment and artificially low revenue for some generators. And the anticipation of future congestion, curtailment and artificially low revenue discourages new renewable energy development.
So why is this no-brainer still stuck in neutral? Well, the entities that control ratings, the transmission owners, don’t benefit from change, and may have perverse incentives to deter new generation entry competing with their units, and/or expand their own transmission facilities instead of efficiently using them.
At the technical conference, some TOs posited various objections to dynamic/ambient ratings, none of which are valid. Let’s check them out.
TOs: Circuit Ratings Can be Limited by Substation Equipment, not the Line (Conductor)
It is true that a circuit’s rating is based on the rating of the most limiting element, and for a given circuit, that element may be a piece of substation equipment rather than the transmission line (conductor) between two substations.
This is not the typical situation, and even when it happens, it does not follow that that’s the end of the story. Substation facilities also have (or should have) ratings that vary by temperature (and sometimes wind as well). These include transformers, with dynamic ratings based on fluid-temperature monitoring that has been available for 20 years[efn_note]See for example this paper, https://kth.diva-portal.org/smash/get/diva2:1155097/FULLTEXT01.pdf. The Exelon representative erroneously said that transformer ratings are not affected by temperature (Tr. 320).[/efn_note] and voltage (reactive) devices. In PJM, there are many temperature-adjusted ratings for transformers and voltage devices.[efn_note]https://edart.pjm.com/reports/PJM_Line_ratings.txt (word search for “xformer” and “ser dev”).[/efn_note]
Transformers and voltage devices that have (or should have) weather-variable ratings are the most expensive substation facilities. There are other types of substation equipment that may or may not also be susceptible to weather-variable ratings, but more important, these types of equipment (breakers, wavetraps, etc.) are relatively cheap to upgrade.
The substation equipment objection lacks merit.
TOs: Transmission Limits Can be Voltage-based Rather than Thermal-based
Another truism that is immaterial. As noted above, voltage devices have (or should have) dynamic/ambient ratings. And where they don’t, the cost of adding new voltage devices may be small. System operators should get the information they need to make rational decisions about this.
TOs: Ambient Conditions Can Differ Along a Given Transmission Line
Another truism that is immaterial. Sure, ambient conditions might be materially different where a given transmission line goes say, into a valley, than say where it goes over a hill. In those circumstances, the transmission operator/owner can install more than one set of weather (or other) sensors on that line, and base the dynamic/ambient rating on the lowest of the resultant ratings. Not rocket science.
TOs: This is Really Complicated, Needs more Study, etc.
This kind of objection to technology that’s been around for decades comes from entities like the MISO TOs that somehow manage to do things like … hmm … operate 10 nuclear plants.
Ambient ratings, at least for temperature, have been used in PJM for decades.[efn_note]https://edart.pjm.com/reports/PJM_Line_ratings.txt.[/efn_note] One example of thousands of these ambient rating sets is below (Degf is temperature Fahrenheit; Norm is normal rating; Long and Shrt are emergency ratings; and Dump is load-dump rating; values are MVA).
| PJM
And PJM now has the capability to use dynamic ratings as well.[efn_note]PJM presentation, page 1.[/efn_note]
Same with CAISO: “Now with the new EMS that we have, we have the capability of implementing any type of an AAR or DLR, you name it” (Tr. 149).
Same with NYISO, which has the “capability to accept DLRs” and use them in its EMS.[efn_note]NYISO presentation, page 2.[/efn_note]
Same with MISO, which testified that it has the capability to handle rating changes in real time (Tr. 239-240).[efn_note]And Entergy, a MISO TO, uses ambient temperature ratings and communicates them to the RTO (Tr. 154-158).[/efn_note]
Basically, most of the RTOs have the capability now to use dynamic and/or ambient ratings.
It’s the TOs that need to step up.
TOs: NERC Standards Take Care of This
In a “nothing to see here” gambit, various TOs claimed that NERC Reliability Standard FAC-008 somehow takes care of all this. In fact, this standard basically says that a TO has to have a ratings methodology and has to comply with whatever that methodology says. Nothing in it says the methodology has to be reasonable, satisfy any other criterion or is subject to review by an objective entity.
Take FAC-008’s requirement that a TO’s ratings methodology explain how “ambient conditions” are considered. It appears that for MISO TOs (other than Entergy) and for countless TOs elsewhere, the explicit or implicit answer is “considered and tossed.” And, tragically, this seems to satisfy FAC-008.
Having gone through the TO objections, let me touch on a couple key points.
The Importance of Wind
With apologies for getting into the weeds, it is critical that wind speed and direction be included along with temperature. Wind dramatically increases ratings, and typically is more significant than temperature as numerous witnesses testified at the conference.[efn_note]Tr 33-34, 38, 52, Lindsey Manufacturing presentation (slide 7).[/efn_note]
Wind dramatically affects ratings almost all the time. PJM has 26 years of data showing this.[efn_note]https://pjm.com/~/media/planning/design-engineering/maac-standards/bare-overhead-transmission-conductor-ratings.ashx (Appendix 1). Looking at the row for the highest temperature of 35 degrees Celsius (95 F), the frequency of 0 to 2 knots (0 to 1 m/s) is 0.104, and the frequency of 3 knots and more is 5.427. This means that when temperature is the highest, wind will increase the rating 98% of the time (1 minus 0.104/5.427).[/efn_note] These data show that when temperature is the highest, the prevailing wind increases the rating 98% of the time. Amazing.
This also responds to a question at the conference about whether dynamic/ambient ratings might sometimes be less than the static rating (Tr. 104). The answer is that if wind speed is considered, this will almost never occur. And in the incredibly rare hour or two that it does occur, then that slightly lower rating could be used.[efn_note]Even if a slightly lower rating isn’t used, it would be inconsequential. In the most common situation where the rating is based on the thermal capacity of the conductor (rather than a sag/clearance issue), the consequence of exceeding the limit is simply a reduction in useful life of the conductor, i.e., accelerated depreciation. And if it’s for a short time, the reduction is trivial. And we need to keep in mind that transmission lines are being replaced when they reach their “end of life” for various reasons, which usually involve the structures (towers) and rarely involve the conductors themselves. So a trivial loss of life for the conductor is inconsequential.[/efn_note]
The Importance of Emergency Ratings
This isn’t really about dynamic/ambient ratings but something that may be even more consequential.
Emergency ratings are short-term ratings that apply to contingencies (i.e., N-1 events) because the nature of contingencies is the loss of a given circuit, causing increasing loading on adjacent circuits, and redispatch within an hour or so to get all circuits back within normal ratings.
PJM for example has had ratings for normal (continuous), emergency and load dump conditions for decades (and as noted earlier also differentiates ratings by temperature).
OK so here’s the news. At the conference it surfaced that there are some TOs, including a lot of the MISO TOs, that use normal ratings as their emergency ratings as well.[efn_note]Tr. 311. By contrast, in PJM, the only TO that had identical normal and emergency ratings is American Electric Power, and then only for 345-kV and above circuits. Last year AEP changed to using different emergency ratings for all circuits.[/efn_note] This is a tragedy.
In operations (dispatch), that means artificial congestion with too low prices and curtailments for some generators, and dispatch of higher-cost generators causing too high prices to load.
In planning, it means unnecessary transmission upgrades to alleviate fantasy overloads, and excessive interconnection costs and delays for new entrants like wind and solar projects.
FERC should put a stop to that as soon as possible regardless of what actions it takes on dynamic/ambient ratings. One way would be to investigate the cost of transmission upgrades that have been based on an N-1 “overload” of a normal rating that is wrongly doubling as an emergency rating. It could also open an investigation into the withholding of available transmission capacity.
Renewable energy developers (and consumers) should not stand for this.
Transition
We know Rome wasn’t built in a day. So we’ll need some sort of transition.
There are two ways of looking at it. What can we do right away? And how do we prioritize the rest?
There’s no apparent reason why TOs across the country can’t do what all the PJM TOs do now, as illustrated above, provide ambient temperature-differentiated normal, emergency and load dump ratings. This is the lowest hanging fruit and can be done on a “desk” basis. No new equipment needed.
From there, priority for installation of dynamic rating capability should focus on the most heavily congested circuits. But if a TO can justify another approach, so be it.
But let’s get going on making the most of the grid we have.
Shell Energy last week asked the D.C. Circuit Court of Appeals to review two FERC rulings in the GreenHat Energy default case after the commission denied the company a role in settlement negotiations in August.
PJM filed an agreement with FERC earlier this month that would see the RTO pay $12.5 million to two trading firms that alleged economic harm after its waived its own liquidation rules to settle GreenHat’s 890 million MWh defaulted financial transmission rights portfolio in July 2018. (See PJM to Pay $12.5 million to End GreenHat Dispute.) PJM also asked the commission to waive the comment period should it receive no negative feedback on the agreement, due with FERC on Oct. 29 (ER18-2068).
E. Barrett Prettyman Federal Courthouse | HSU Builders
It’s unclear if Shell will protest the settlement or request payout from the $5 million fund PJM would establish for additional claimants, per the agreement. Jonathan Franklin, Shell’s attorney, did not respond to RTO Insider’s request for comment. Attempts to contact Shell itself were also unsuccessful.
Shell pleaded with the commission in July for a role in settlement negotiations, saying it was “uniquely situated” in the proceeding and could bear a disproportionate financial burden based on its outcome. The company filed one of the more than 20 late motions to intervene that were dismissed by FERC in the June 5 order.
In its request for rehearing, Shell said a PJM Tariff provision caused its tardiness, a circumstance that it says none of the other petitioners faced. It had explained that it entered into three bilateral contracts with GreenHat that involved transferring FTRs back and forth between the two companies. Liquidating the GreenHat portfolio “could substantially affect the amount sought by PJM from Shell for the guarantee and indemnification claim” the RTO placed on the portion that was transferred. (See Shell Energy Seeks to Avoid Liability in GreenHat Trades.)
In August, the commission said it found Shell’s argument “unpersuasive,” reiterating that the company had no excuse for an untimely intervention.
Jeff Shields, a PJM spokesperson, told RTO Insider on Friday the RTO doesn’t expect Shell’s appeal to affect the settlement proceeding, noting that “obviously FERC will be able to take into account any comments that are filed.”
LITTLE ROCK, Ark. — An August energy emergency alert (EEA) that had SPP one contingency away from shedding load has renewed calls for scarcity pricing or other measures to ensure adequate reserves.
Unplanned outages, low wind and a bad forecast combined to create tight operating conditions on Aug. 6. That forced SPP to call its first EEA since becoming a consolidated balancing authority in 2014. The RTO resolved the situation by calling on 478 MW of grid-switchable resources in ERCOT and curtailing up to 127 MW of non-firm export capacity. (See “Staff Evaluating Procedures After Aug. 6 EEA,” SPP Seams Steering Committee: Sept. 11, 2019.)
“We had no other generators,” SPP Operations Director C.J. Brown told the Markets and Operations Policy Committee on Oct. 16. “We maintained that day just fine, but one more contingency and we would have been at a higher level of EEA. We would have been turning the lights off, and that’s close to me.”
SPP’s load peaked at 49,389 MW on Aug. 6, a little more than half of its nearly 90 GW of nameplate capacity. However, wind production was at only 7% of its 22.3 GW of installed capacity.
Brown said generation outages have become commonplace during recent summers. MOPC members suggested wear and tear from fossil units cycling and up down to meet demand has much to do with that, a notion Brown agreed with.
“These are machines. They’re not going to run 24/7, 365 days a year,” he said. “We see a definite uptrend of planned outages over the summer. We want to look at that. It doesn’t seem to be an anomaly. Why are we seeing more planned work in the summer? What’s the driver? Can we do anything about it? We want to look into it further, and we need your help with that.”
SPP has suggested creating a generator outage task force to assess trends and potential causes, making improvements to supply adequacy requirements, and verifying assumptions in loss-of-load expectation planning studies. It is already trying to determine its real-time capacity, as opposed to planning capacity, and working to develop more specific declarations beyond EEAs, weather alerts and calls for conservative operations.
Monthly average of MWs on outage (no wind) | PJM
The Market Monitoring Unit has proposed reliability pricing rules during EEAs and maximum generation events to incent generator performance. Noting that day-ahead prices barely reached $25/MWh during July and August, the Monitor’s Greg Sorenson said market prices did not reflect emergency conditions because capacity commitments and generation added to address the conditions frequently lowered prices.
“If SPP wants generators to be available during an emergency, prices do not reflect that,” Sorenson said. “Other markets have rules that incent generation.”
While real-time prices briefly spiked to nearly $1,500/MWh during the August EEA, Golden Spread Electric Cooperative’s Natasha Henderson questioned the market’s price formation.
“I see a lot of sticks and not enough carrots,” she said.
Listening to the discussion, Mike Wise, Golden Spread’s senior vice president of regulatory and market strategy, stood and delivered an impassioned speech on the value of scarcity pricing. It’s a mechanism he is very familiar with, as Golden Spread also operates in ERCOT.
“I’m going to use the s-word that is not popular with many of you sitting here today,” Wise said. “Scarcity pricing works. Although several here will disagree, I believe we need to consider moving towards this strategy for our pool.”
While scarcity pricing may be sacrilegious to some in SPP, Wise pointed to ERCOT’s ability to meet record demand this summer despite similar wind-energy shortages that led to tight operating conditions. He said the lack of price-responsive load in the SPP market could be because of “market prices not reflecting the actual scarcity.”
The ERCOT “market is seeing price-responsive loads taking the price signals and curtailing themselves,” he said. “This summer … saw over 3,000 MW of price-responsive load get off across their peak as the reserves were getting low and the price adders for the lack of reserves made the market price go very high. So, if prices in the SPP were allowed to correctly reflect scarcity of reserves, then those utilities would find it in their best interests to change their maintenance plans.
“This market has got to change, and soon, as we continue to add all these intermittent renewable resources, and our legacy generation assets are used less and less for actual energy and more for reserves and market support,” he said.
MOPC Chair Holly Carias, with NextEra Energy Resources, emailed committee members last week to request their feedback and next steps on staff’s and the MMU’s recommendations.
“We want to work with our stakeholders,” Brown said. “That makes the most sense.”
AUSTIN, Texas — An attempt by ERCOT legal staff last week to alert stakeholders that qualified scheduling entities (QSEs) will soon be required to submit certificates for the resale of electricity resulted in a bit of a kerfuffle.
Stakeholders pushed back against the proposal during the Technical Advisory Committee meeting Wednesday, complaining about what they saw as an added compliance burden and asking to see the legal opinion behind the proposal.
ERCOT Senior Corporate Counsel Erika Kane held firm, beginning her responses to repeated questions with, “Again…”
Other legal staff began filtering into the meeting room, with General Counsel Chad Seely eventually joining the fray.
“I haven’t heard all the discussion. I just got text messages,” Seely said, taking a seat at the table.
In teeing up the subject, Kane said that electricity sold in Texas for end use is a taxable good subject to sales tax, unless a tax exemption applies. The purchaser — the QSE — claiming a “sale for resale” exemption must provide a resale certificate to the seller to establish an exemption from sales tax. Tax-exempt entities, such as municipalities and cooperatives, can choose to provide a tax-exemption certificate.
Kane said ERCOT was only asking QSEs to conform with practices followed by other RTOs and ISOs, who have determined that their role as central counterparty raises a need for the certificates’ submission.
“We came to conclusion that looking at risk versus burden, this is the right path forward,” she said.
The subject had been discussed at the board level and with outside legal counsel, but not with stakeholders. Seely said that “through a lot of discussion,” staff felt it necessary to put in place a process to gather the sales tax resale certifications.
“Help us understand the onerous burden placed on QSEs to fill out this documentation,” he told stakeholders.
Reliant Energy Retail Services’ Bill Barnes said that while the certification may be simple, “it feels like ERCOT has had an awakening or a new interpretation of the protocols that has caused a concern and proposed to be resolved by pushing the burden onto all the QSEs.”
“It adds to the host of all other documentation we have to file when we register a new QSE or change a name and address, which some of us do quite a bit,” Barnes said. “It’s another form and requirement we need to remember to do, when it appears to us there’s an easier way to do it. We’re not getting a good answer as to why there’s not a simple statement in the protocols that clarifies ERCOT can’t and does not sell electricity to end-use customers.”
Noting the layers of laws ERCOT operates under, Seely said, “You can’t place a requirement that would usurp the Texas tax code in the protocols.”
Seely said there was no outside legal opinion to share with stakeholders — “Everything I’m saying has been run through outside counsel,” he said — and he seemed nonplussed when one member asked whether the state’s comptroller could come to the committee and offer its opinion.
“You want the comptroller to come into this forum?” Seely asked.
“The comptroller hasn’t had a problem with how we’ve operated for 19 years,” Morgan Stanley Capital International’s Clayton Greer said. “That’s baffling to me,” he added, referring to ERCOT’s proposed change.
“I don’t know why it’s baffling,” Seely responded. “Just because the comptroller hasn’t said anything doesn’t mean we shouldn’t be addressing the issue.”
Staff had intended to put out a market notice after first giving the committee a heads-up. Now they plan to return to the committee in November with additional information and a new plan for moving forward.
Staff told the committee they plan to ask the Board of Directors for permission to revise day-ahead and real-time prices for 13 operating days. ERCOT protocols require the grid operator to resettle prices to right the wrongs of any data mistakes.
Kenan Ögelman, ERCOT’s vice president of commercial operations, assured market participants that the price corrections will be made, but he said staff first need to finish their analysis. That data will be shared with the Wholesale Market Subcommittee on Nov. 6 and the TAC during its Nov. 20 meeting.
Ögelman said a May update to the ERCOT’s market management system, intended to model withdrawn outages in the day-ahead market and for reliability unit commitment where facilities were being restored, instead modeled all withdrawn outages. Outages withdrawn before their planned outage start date were erroneously modeled in the market as out of service.
“The transmission and distribution providers did everything exactly as they were supposed to,” Ögelman said. “It’s how our systems took that in and what they did with it. It was not about anything coming in incorrectly externally.”
“ERCOT should correct prices when they screw up the data,” said Beth Garza, director of the grid operator’s Independent Market Monitor. “This is an ERCOT-screwing-up-the-data thing. ERCOT has an obligation to correct and inform.”
When ERCOT became aware of the error in late September, staff began investigating prices for the May 30 to Sept. 25 operating days, Ögelman said. A patch was placed into production Sept. 26.
Staff identified erroneously modeled outages for the Aug. 20-21 and Sept. 16-25 operating days. They determined that only the Sept. 16-23 prices were eligible for board review.
Ögelman said the August prices could not be corrected, as they were outside the timeline for board review. However, staff were able to re-price the Sept. 24-25 days before the prices became final.
On Oct. 24, ERCOT notified market participants that a recent update to the energy and market management system led to incorrect real-time prices Oct. 16-21 for certain settlement points and energy metered for resources. The grid operator said it has corrected the Oct. 21 operating day prices, which were still within the review timeline.
ERCOT said it would begin the resettlement process about a week after the Dec. 10 board meeting.
TAC Approves BESTF Leaders, Scope
One month after approving the creation of a task force to best integrate battery storage into ERCOT, the TAC endorsed the group’s leadership and charter. (See “TAC Approves Task Force to Study Battery Energy Storage,” ERCOT Technical Advisory Comm. Briefs: Sept. 25, 2019.)
Members unanimously backed the Battery Energy Storage Task Force’s selection of ERCOT’s Ken Ragsdale as its chair and Lower Colorado River Authority’s Andy Nguyen to represent stakeholders as the vice chair.
Ragsdale demurred to Sandip Sharma, ERCOT’s manager of operations planning, as being the group’s real leader despite the title. “He’s our guiding light,” Ragsdale said.
According to its charter, the BESTF will develop policy recommendations for the TAC’s consideration that relate to the integration of battery energy storage resources into the ERCOT system.
Two issues are currently “pressing” on the task force, Ragsdale said. The first is filing Nodal Protocol revision requests (NPRRs) related to a single model to be incorporated along with real-time co-optimization upgrades in the first quarter of 2020. The second is beginning discussions by midyear on how to integrate hybrid resources (battery and thermal) and DC-coupled resources, where the battery and solar are both behind the inverter.
The group defines a single model as a future approach where the battery is a single resource. It defines the combo model as the current approach representing a battery as a generating resource and a controllable load resource.
“We hope to come up with a proposal in early January and get some ideas on what the solution is before the second quarter of 2020,” Ragsdale said.
The BESTF held its first meeting Oct. 18 and has two more scheduled this year. It plans to follow the same review process as the Real-Time Co-optimization Task Force (RTCTF) by first developing principles or key topic/concept (KTC) recommendations that will be used to write the revision requests. The group plans to bring its first KTCs to the TAC’s Nov. 20 meeting.
“We’re still doing our homework,” Ragsdale said. He said the group is checking with other grid operators, developers and the Electric Power Research Institute to understand the design drivers.
Energy storage roadmap | ERCOT
RTC KPs
The committee endorsed the largest batch of real-time co-optimization key principles — 19 in all — yet offered up by the RTCTF.
The principles (KPs) fall under three categories:
KP 1.1 (5): Defines ERCOT’s parameters in representing the disaggregation of ancillary service (AS) demand curves so that potential future changes in values and distribution will not require system changes.
KP 1.3 (1)-KP 1.3 (11): Outline the key mechanisms and timelines for submitted AS offers and the AS considered and awarded under real-time co-optimization.
KP 5 (1)-KP 5 (6): Identifies day-ahead market changes necessary to align day-ahead AS procurement with real-time co-optimization’s implementation.
ERCOT’s Matt Mereness, who chairs the RTCTF, promised more than 20 items in KP 5 before the group is finished.
The task force has six meetings left, with the final one scheduled for Jan. 22. “We’re going right up to the wire,” Mereness said.
Members Endorse 9 Revisions
TAC members approved six NPRRs, a change to the Nodal Operating Guide (NOGRR) and two system-change request (SCRs):
NPRR849: Clarifies the range of voltages at a generation resource’s point of interconnection and circumstances for which its reactive capability must be designed to meet.
NPRR902: Defines ERCOT Critical Energy Infrastructure Information (ECEII), adds items that are considered ECEII, specifies the restrictions imposed upon parties that receive or create ECEII, and provides a framework for the submission of ECEII to ERCOT.
NPRR937: Removes distribution-level and non-settlement metered block load transfers from deployment during Level 2 energy emergency alerts (EEAs).
NPRR965: Excludes a quick-start resource’s five-minute intervals from the generation resource energy deployment performance calculation when the resource is engaging in the decommitment process or telemetering “shutdown” status.
NPRR968: Updates Protocol language to comply with NERC reliability standards BAL-002-3 (Disturbance Control Standard – Contingency Reserve for Recovery from a Balancing Contingency Event) and EOP-011-1 (Emergency Operations) by changing the physical responsive capability trigger for a Level 3 EEA to match a new most severe single contingency of 1,430 MW, to be implemented on Jan. 1, 2020.
NPRR969: Clarifies ERCOT is the final authority in qualifying market participants.
NOGRR197: Updates the responsive reserve service (RRS) manual deployment to provide flexibility in the amount of RRS capacity that is released to the security-constrained economic dispatch engine during scarcity conditions.
SCR800: Incorporates DC tie-scheduled ramp into SCED by updating the resource limit calculator’s formula to determine the generation-to-be-dispatched value and adding a scheduled five-minute DC tie ramp rate (DCTRR). The DCTRR will be calculated from the scheduled systemwide DC tie ramp multiplied by five and a configurable factor to capture the scheduled five-minute ramp.
SCR805: Allows ERCOT to automatically provide certain reports to requesting transmission service providers (TSPs) before they are posted to the market information system public area. TSPs will receive the reports once a formal request has been approved by ERCOT.
LEXINGTON, Ky. — FERC Chairman Neil Chatterjee’s EnVision Forum, held last week at the University of Kentucky, was a unique energy conference in several ways, from the diverse lineup of speakers, to the wide variation in panel topics.
Perhaps most unique, however, was its location.
It wasn’t just the fact that it was held in a university football stadium. Or that lunchtime dessert featured bourbon-frosted bread pudding.
For his inaugural annual event Oct. 21, Chatterjee chose his home state, a place dependent on coal mining for its economy and coal-fired plants for most of its power, with 75% of its electricity generated by coal last year, according to the U.S. Energy Information Administration. It’s the fifth largest coal producer in the U.S., and about one-fifth of all operating U.S. coal mines are located there, according to EIA.
And judging by several of the panels at the conference, the state doesn’t care too much about the national conversations in the electricity industry: the increasing penetration of renewables, the threat of climate change and the need to modernize the grid.
“Well first off, I want to not apologize for the things we haven’t jumped on the bandwagon for,” Kentucky Public Service Commissioner Talina Mathews said in opening “Lessons from Kentucky: A Case Study in the Energy Transition.”
“We remain vertically integrated. … We remain predominantly fossil fuel[-powered]. We don’t have a [renewable portfolio standard]. … But what we do have is reliable, baseload generation that serves our homes and also serves a large manufacturing base in Kentucky,” Mathews said. “We make things here, and I think that may be different from some of the other states that maybe have the ability to rely on more intermittent sources of energy. I don’t think an aluminum smelter is going to deal very well with anything under a 90% load factor.”
Chris Perry, CEO of the Kentucky Association of Electric Cooperatives, referred to an earlier panel entitled “Empowering 21st Century Energy Consumers with Technology,” which featured Jeff Riles of Google and Brian Janous of Microsoft.
“They were talking about … a two-way communication, where customers are really engaged, getting a carbon signal, adjusting their usage. Let me tell you, in rural Kentucky, that’s not happening,” he said.
A member of the audience asked whether utilities in the state disclose electricity usage to ratepayers. “Sure,” Perry said. His co-ops also provide voluntary demand response programs. “Guess how many people sign up? Not many. Not many. We find out they get excited for a short period of time, and then it’s, ‘I want to dry my clothes when I want to dry my clothes.’”
Another audience member asked the panel, which also featured Kentucky Power President and COO Brett Mattison and LG&E and KU Energy CEO Paul Thompson, if their utilities were seeing increased customer demand for renewables as in the rest of the U.S.
“We don’t have the best resources,” Mathews said. “I jokingly say Kentucky is the allergy capital of the world because the wind hits the plains and then all of a sudden it just stops, and we breathe pollen from April to November. …
“You would never build wind here if you can build it in Oklahoma,” she said, making a similar comparison with solar and Arizona. “So, we’ve heard, but we really haven’t had many of those [renewable projects] come to the commission.”
“You have many customers who sometimes will say, ‘Well we’d like to see some renewables; we’d like to see some zero-carbon energy,” Big Rivers Electric CEO Robert Berry said. “But they’re not really interested in paying for it.”
Berry said a co-op survey revealed 40% of its customers wanted to get their electricity from solar, but only 20% were willing to pay “some amount” more for it. Only about 5% were willing to pay 2 to 3% more, he said.
Kentucky had the seventh-lowest average electricity price in the U.S. last year and the lowest price east of the Mississippi River, according to EIA.
The argument that the switch to renewables would cost low-income ratepayers more was one that continually came up on an earlier panel entitled “All of the Above vs. Green New Deal,” the latter a reference to a Congressional resolution to transition the U.S. to 100% zero-carbon energy by 2030. Moderated by former FERC Commissioner Colette Honorable, the panel featured several state utility commissioners, most of whom criticized the Green New Deal as too costly for their customers.
“I represent the poorest region in the poorest state in the United States of America,” Mississippi Public Service Commissioner Brandon Presley said. “And the impact of an electric bill on a Mississippian is much more than it is in many other places in the United States of America. It affects our cost of living.”
“In the Eastern Kentucky footprint, where we serve, we have the same exact thing,” Mattison said on the Kentucky panel, referencing Presley. “Probably 30-plus-percent of the individuals find themselves at or below the poverty line. So when you look at transitioning to new sources, there’s always a cost associated with that. … We have constituents and customers who can’t afford to pay for that.”
Speaking on the earlier panel, Richard Kauffman, chairman of the New York State Energy Research and Development Authority, pushed back against these arguments.
“This issue of affordability I think is a red herring,” he said. “You [need to] create the right kind of innovation and market-related practices and change the financial incentives and business model for distribution utilities to be more system integrators as opposed to just being in the business of deploying capital — because that’s one of the reasons we have such low average capacity utilization.”
Wisconsin Public Service Commissioner Ellen Nowak responded. “I think it is a real concern. In my state, we have a lot of manufacturers, and the margins on their profit are very dependent on the cost of their energy. And as an economic regulator, we have to be smart about what we’re requiring them to pay for. That’s why this transition has to be done in a meaningful manner, not in a date that you set out and then figure out how you get there.”
“If we’re not careful, we’re going to burden all customers with a lot of stranded assets,” Kauffman said in reply. “Capital and energy inefficiency is a burden that we’re currently imposing on customers, and we can get more out of the customer bill. Think of that as a cost offload.”
Impact on Communities and Workers
Another panel focused on the impacts of the “new energy economy” on coal-dependent communities.
“Kentucky, like many states, has experienced firsthand the workforce and community impacts of our changing fuel mix,” Chairman Chatterjee said in an opening speech. “Behind every major energy project and company are dedicated energy sector workers. These women and men work hard to expand, improve and modernize our nation’s energy infrastructure and serve as the humming engine of our energy economy. …
“Right here in Kentucky, we’re in the heart of coal country. … The [coal] plant retirements that we’ve been seeing have real impacts on the workers, families and local economies here in Kentucky and throughout the United States.”
The panel wasn’t as dour as one might have expected, but it still illustrated the challenges blue-collar workers will increasingly face as coal plants continue to shut down and nuclear plants remain uneconomic to build.
Speakers included Brian Kerkhoven, energy policy adviser for North America’s Building Trades Unions, a federation of 14 unions that includes the International Brotherhood of Electrical Workers. Kerkhoven said his organization offers apprenticeship programs to train “out-of-work coal miners, who sure as hell aren’t going back to become nurses,” to become construction workers.
“We are now seeing a huge growth in our pre-apprenticeship program,” Kerkhoven said. “Not everybody has to go to college anymore, and we’re trying to lead that charge. … And that’s going gangbusters,” particularly in Texas.
He said renewables “don’t create the amount of jobs that coal, nuclear and even natural gas, to a certain extent, create. … Six to seven hundred people go to work every day at a nuclear power plant. A team of five to 10 go around and make sure the windmills are still spinning.”
Donnie Colston, director of IBEW’s Utility Department, concurred, saying the union’s members work on all resource types, but gas units, wind turbines and solar panels require very little maintenance compared to coal and nuclear plants.
“The good thing is … we’re being able to move” workers at shuttered coal plants “into other positions where members are retiring,” Colston said. “We’re not having massive layoffs.”
That still involves teaching workers a new trade. Utilities need to wait three to eight years, for example, for new linemen to complete their apprenticeship programs, he said.
Colston was incensed by the failure of states to approve interstate transmission lines, citing New Hampshire’s rejection of the 192-mile Northern Pass line that would have brought Canadian hydropower to Massachusetts, and Arkansas’ rejection of the 720-mile Plains & Eastern Clean Line, which would have transported wind energy in Oklahoma to the Tennessee Valley Authority.
“We worked for probably eight years with Eversource Energy” on Northern Pass, Colston said. “That was 2,000 jobs for IBEW. It came down to one vote on one committee that eliminated eight years’ worth of work. …
“Now, I don’t think we want to take away a state’s right to say you can’t build the lines, but if you want clean energy, as baseload comes off, you got to build lines,” he said.
Stakeholders are insisting PJM should manage critical infrastructure planning, telling the Board of Managers that a proposed Tariff attachment from incumbent transmission owners would violate the RTO’s governing documents.
LS Power and American Municipal Power are leading the chorus of dissent arising among stakeholders over Attachment M-4, which would establish a confidential process for mitigating the risks related to transmission facilities on NERC’s CIP-014-2 list — a subset of supplemental projects with regional implications that some members believe belong under the purview of PJM.
“PJM is a creature of both its Operating Agreement and Tariff, and PJM must pursue sound public policy consistent with the legal confines of both its Operating Agreement and Tariff construct,” LS Power wrote in a letter to the board Wednesday. “The proposed M-4 proposal construct has glaring inconsistencies with the existing regional planning process and the PJM Operating Agreement, which is controlled by the members of PJM, not the transmission owners.”
CIP-014-2 requires TOs to identify and protect transmission stations and substations whose loss or sabotage could result in widespread instability, uncontrolled separation or cascading outages. In August, incumbent TOs proposed outlining a process for vetting transmission projects in order to remove the assets from the list.
| Plocher Construction
Competitive transmission developers, consumer advocates, state commissions and other load interests argue the attachment is riddled with flaws that ultimately guarantee incumbent TOs control over a subset of complex supplemental projects with RTO-wide impacts, all under the guise of NERC-required confidentiality. (See PJM TO Tariff Filing Stirs Up Transparency Concerns.)
“Given the importance of these substations to regional and possibly interregional operations, there can be little question that the planning of those substations would be conducted through the PJM-administered regional transmission planning process,” AMP said.
PJM proclaimed its neutrality in the debate and only committed to the mutual agreement among all sectors that transmission planning should aim to eliminate the assets deemed critical within the RTO’s footprint, of which incumbent TOs say less than 20 exist. (See PJM Remains Neutral in CIP-014 Debate.)
But staff’s refusal to take sides hasn’t stopped stakeholders from taking their concerns straight to the board.
“We wish to emphasize that we can protect our critical energy infrastructure and maintain our national security, while also opening up the processes to build or upgrade such regional infrastructure to competition,” Securing America’s Future Energy (SAFE) said in a letter dated Oct. 3. “Contrary to the claim by the TOs, national security and market competitiveness are not mutually exclusive.”
SAFE further described a separate process for vetting CIP-014 projects as unnecessary and rejected the argument “that such transmission lines cannot or should not be allowed to be bid through a competitive process.”
In a Sept. 24 letter, the Organization of PJM States Inc. (OPSI) said that TOs should bring state commissions deeper into the CIP-014 planning process and specify how many critical facilities exist within each zone. The group also wants to know when these projects get factored into PJM’s Regional Transmission Expansion Plan and suggested TOs develop an assessment that balances cost and consequence reduction associated with each project.
The recommendations channel a problem statement and issue charged sponsored by the D.C. Office of the People’s Council that encourages stakeholders to develop a CIP-014 process inclusive of all sectors. The Planning Committee voted on Oct. 17 to postpone voting on the proposal pending a TO-led webinar to address questions. (See “Critical Infrastructure Vote Delayed,” PJM PC/TEAC Briefs: Oct. 17, 2019.)
Beyond PJM’s Control
The issue intersects with stakeholders’ overall concerns about supplemental project planning, which PJM insists it has little authority over. (See PJM TOs Sign off on Supplemental Project Deal.) Board Reliability Committee Chair Dean Oskvig said on Oct. 4 that the managers’ review of supplemental projects concluded that the RTO’s role “can be expanded in some areas but also remains appropriately constrained in others.”
“PJM does not have the authority or expertise to assume responsibility for asset management decisions or to determine when a facility is at the end of its useful life or otherwise needs to be replaced,” he said, referencing a failed AMP-sponsored problem statement and issue charge that wanted to open up these projects to regional planning. “Those decisions are the sole responsibility of the transmission owner.”
According to the Oct. 31 agenda for the Markets and Reliability Committee, AMP will present its failed problem statement and issue charge for a first read. (See “PJM Says No to End-of-Life Transparency Discussion,” PJM PC/TEAC Briefs: Sept. 11, 2019.)
Interim CEO Susan Riley echoed Oskvig’s sentiments in response to Consumer Advocates of the PJM States over what the organization called the unfettered growth of supplemental projects in comparison to necessary system upgrades planned by PJM.
“It is important for the PJM community to remain cognizant of where PJM’s authority and technical capabilities are positioned in relation to the planning and implementation of supplemental projects,” she said. “Identifying and verifying the need for supplemental projects, determining what goes into a transmission owner’s planning criteria and authorizing supplemental projects are responsibilities that extend beyond where PJM is situated as the regional transmission planner.”
In multiple responses addressing the CIP-014 process exclusively, Riley said the board understands the profound implications of these projects and said stakeholder comments provide constructive feedback for TOs in the ongoing development of their proposal.
“CIP-014 mitigation presents unique challenges related to the balance between significant risks imposed on customers and the transparency that has been at the foundation of the PJM planning process,” Riley told OPSI in a letter dated Oct. 8. “We discussed this matter at our last board meeting and commit to work with all stakeholders to develop a process that will allow the transmission owners to mitigate the risk associated with these critical facilities with PJM oversight.”
SCOTTSDALE, Ariz. — The often tense relationship between California and other Western states occupied much of this year’s Transmission Summit West, where the debate focused on whether states such as Idaho and Wyoming should draw closer to the Golden State or keep their distance.
The summit was held in conjunction with the Mountain West Renewables Summit, both organized by Infocast, at the Scottsdale Resort at McCormick Ranch.
Some speakers at the summits argued that a Western RTO made eminent sense, while others said their states didn’t want to feed California’s appetite for renewable energy without seeing enough benefits in return.
Arizona, for instance, is a politically conservative state with low electricity costs, said Michelle De Blasi, executive director of the Arizona Energy Consortium, a group that promotes the state’s energy industry. Arizona has the nation’s largest nuclear power plant, the 4,000-MW Palo Verde Generating Station, and one of the country’s youngest coal fleets, De Blasi noted. Both produce low-priced electricity that benefits Arizona ratepayers, she said.
Arizona’s electric utilities will take California’s solar power, particularly when there’s negative pricing, but they haven’t found interstate cooperation sufficiently useful to justify major investments, she said.
“It hasn’t made sense for them to go and build power lines and build generation feeding outside of the state,” De Blasi said. “We did not want to be a giant outlet for California.”
The state’s largest utility, Arizona Public Service, is a member of CAISO’s Western Energy Imbalance Market. Salt River Project and Tucson Electric Power plan to join in 2020 and 2022, respectively.
Some utilities of the interior West have determined the savings achieved through the EIM — a wholly voluntary, real-time interstate trading market — make it worth rubbing shoulders with CAISO, despite their states’ political differences with California. CAISO says the EIM saved its nine-member utilities more than $736 million in the past five years.
Interior states aren’t keen to get much closer to California than the loosely knit EIM, however.
Large areas of Wyoming and Idaho are served by PacifiCorp, an EIM member. But utility commissioners from those states expressed misgivings at the summit about serving California’s needs with renewable energy, paying for transmission upgrades or joining a CAISO-led RTO.
Who Pays for New Transmission?
During a panel titled “Enabling California to Access Out-of-State Resources,” David Smith described the TransWest Express, a proposed 730-mile transmission project that would link the wind-producing areas of Wyoming to Southern California via Utah and Nevada. Currently there’s little transmission linkage between California and Wyoming.
“TransWest is a project that would fill in that gap from Wyoming into the existing transmission capacity,” said Smith, the project’s director of engineering and operations.
The problem is, who pays for the project’s estimated $3 billion cost?
California would receive the energy to help fulfill its ambitious clean energy goals. Under last year’s landmark bill, SB 100, the state must rely entirely on carbon-free electricity sources by 2045.
Wyoming and other states would export that electricity, helping to offset the loss of coal production. A company controlled by billionaire Philip Anschutz, who also owns vast wind farms in Wyoming, would develop the project.
Smith suggested the costs of the new high-voltage lines should be shared among those who would benefit.
Public and private investors are part of the plan. The Western Area Power Administration is supporting the project through its Transmission Infrastructure Program, and the federal Bureau of Land Management is a backer. (See Wyoming Wind Power Revs up, but is it too much?)
Kristine Raper, a member of the Idaho Public Utilities Commission and an outspoken critic of California’s policy-driven energy goals, said she doesn’t see much upside to the proposal.
“Why would you socialize the cost of transmission in order for California to meet its renewable energy goals?” Raper said. “Idaho doesn’t have the same goals as California does in order to meet renewable energy,” nor does it need out-of-state electricity to meet its needs, she said.
Wyoming Public Service Commissioner Mary Throne expressed similar reservations in panels on Western regionalization and the allocation of transmission costs. She said Wyoming’s wind farms are no substitute for its once thriving coal industry, which has been shutting down.
“The number of renewable jobs will never replace the coal jobs we’re losing,” Throne said. “Coal to wind is not an even trade in Wyoming.”
Coal isn’t a “four-letter word” in Wyoming, like it is in California, she said.
“We kinda like coal in Wyoming,” Throne said. “It pays our bills.”
The idea of forming an organized Western electricity market, especially one with California leading it, generated even more controversy than the transmission line proposal.
In a presentation called the “Rationale for Western Grid Integration,” Johnny Casana, a senior manager with Pattern Energy Group, a San Francisco-based renewable energy firm, laid out his case for regional cooperation.
Historically, much of the West’s transmission has been built to serve load in California, which has a huge population compared with the sparsely inhabited states of the Intermountain West, Casana said.
In a decade, wind and solar projects may be cheaper to build than keeping natural gas and coal-fired generators running, he said. Inexpensive energy from windy states such as Wyoming and sunny ones such as Arizona could fuel the cities of the West Coast, benefiting all involved, he contended.
“This is a world we’re going into that is unlike the world we come from,” Casana said. “There’s a lot of winners across the board when we think of ourselves as a unified region.”
Compared to the West, the eastern U.S. is far more connected with greater generating capacity, he noted. RTOs are the norm in the Eastern Interconnection; the West needs to catch up, Casana argued.
“We have a shared destiny with our neighbors,” he said.
Some speakers agreed, particularly environmentalists from California advocating for a greater dependence on out-of-state renewables. The proposed expansion of the Western EIM, a five-minute market, to an extended day-ahead market (EDAM) is seen by many as the next step in the evolution of the West’s energy landscape.
Samuel Golding, president of Community Choice Partners, a Los Angeles group that advocates for community choice aggregators (CCAs), moderated a panel on the EDAM. Representatives of CAISO, the EIM and environmental groups spoke on the panel, supporting the move. Like the EIM, they said, the EDAM would be voluntary, with utilities keeping control of their assets and allowed to leave at will.
“If you don’t like it … you can get out of it the next day,” said Craig Lewis, executive director of the Clean Coalition, a nonprofit that advocates for a quicker transition to renewable energy. He criticized some from the interior West for disregarding the potential windfall if they join with California and help serve its energy goals.
“There’s this massive economic development to your states, and it doesn’t seem to be part of the consideration,” Lewis said.
During the panel on transmission cost allocation, Raper said the EDAM could increase the likelihood of a Western RTO. But she said there’s a slim chance other states will join an organized market whose leaders are chosen by California’s elected officials.
Members of CAISO’s governing body are appointed by California’s governor and confirmed by its State Senate — meaning the ISO’s agenda is dictated by the state’s progressive policy goals, she said. CAISO takes control, but not ownership, of the transmission lines of its member utilities. A Western RTO could only happen if California agrees to a board composed of representatives from other states, she said.
“It would be irresponsible for me as a regulator to cede all the assets of my utilities to California,” Raper said.
Given the costs and increasing impacts on resource choices that PJM market rules impose on states, states would benefit from a larger voice at PJM. Compared with its counterparts in other regions, the Organization of PJM States Inc. (OPSI) has less formal engagement and influence on PJM rules and decisions. Strengthening the role of OPSI’s 14 members (13 states and D.C.) would help ensure that states have meaningful opportunities to influence PJM’s rules and policies and could benefit everyone: states, retail and wholesale customers, and PJM.
One example of a PJM rule that impacts state renewable policies and costs to customers is PJM’s proposed change to its capacity market, the expansion of its minimum offer price rule currently under review at FERC. The proposal is estimated to cost customers in the PJM region an additional $5.7 billion per year.
PJM’s footprint | PJM
While the Federal Power Act generally provides PJM states a say over critical energy matters such as resource adequacy planning — how future energy needs will be met — states have seen their influence wane as PJM market rules and policies weight the scales that shape the mix and cost of capacity resources. As a result, PJM’s markets operate increasingly at odds with state energy goals, often at consumer expense.
Like many RTOs, PJM has an official auxiliary group through which states in theory can make their collective voices heard on policies and market rules: OPSI. Consisting largely of state public utility commissioners, OPSI monitors PJM, submits comments and interfaces with the RTO’s board and staff. Unlike state organizations in other RTOs, however, OPSI plays little more than an advisory role. PJM’s current structure leaves states without power to vote on proposed market rules or to file alternatives with FERC.
States’ abilities to directly influence RTO actions vary by region across the U.S. PJM states sit at one end of the spectrum, without voting ability and unable to file challenges with federal regulators. On the other end, states in SPP wield the most authority of any RTO state organization over generation and capacity matters. Taking a look at how RTOs in other parts of the country allow for state engagement is instructive as states in PJM strive for more voice and a better balance between their individual goals and the important role of the regional grid and markets. We overview several RTO/state models in a recent white paper.
Making PJM’s State Committee Work for States
Inspired by the examples of other RTO state committees, here are a few ways to increase the role and influence of PJM states:
Create stronger communication and collaboration between PJM and states: RTOs in other regions give deference to the views of state committees regardless of their rules. They prioritize a constructive working relationship.
Provide regular opportunities to provide formal input: OPSI should be able to weigh in on the design of PJM’s capacity market and transmission planning, both of which influence billions of dollars of supply investments and customer impacts.
Back OPSI’s feedback with bylaws: PJM’s governing documents could have specific opportunities for states’ input and require the RTO to say how it took OPSI’s input into account.
Give states more power to determine their own capacity needs: By adopting a provision like that available in MISO, individual states would be able to set their own targets for capacity reserves — rather than relying on a single target set by PJM — to better reflect state needs and energy goals.
Give states the option to supply their own capacity needs: A so-called “fixed resource requirement option” would give states and utilities more flexibility to meet demand on a megawatt-by-megawatt basis.
Give OPSI the power to make FERC filings: OPSI could be given the power to make its own filings to FERC under FPA Section 205, giving the states more power over resource adequacy planning.
Give states a role in selecting PJM’s board members: In MISO, for example, the state committee is often represented on the search committee for the RTO’s board members.
Require PJM to file states’ alternative proposals: PJM could have a provision where it must file an alternative approved by some percentage of OPSI members. In ISO-NE, the percentage is at least 60% of New England Power Pool participants.
These suggestions are not new, but the events of recent years renew their urgency: PJM is proposing significant changes to its market while searching for its next CEO, public utility commissioners have ongoing concerns about consumer costs, and many states are racing toward a renewable energy future.
Changing the balance of power between PJM and its states is critical to prepare the nation’s largest energy grid for the new energy era that lies ahead.
Ann McCabe returned to consulting after her term as a commissioner at the Illinois Commerce Commission (March 2012 to January 2017). Her recent clients include The Climate Registry, PJM Clean Energy Advocates and the Mid-America Regulatory Conference (MARC). While a commissioner, she was president of the OPSI board and of MARC and chaired NARUC’s subcommittee on Nuclear Issues-Waste Disposal.
David A. Svanda, a principal at Svanda & Coy Consulting, follows PJM, SPP, MISO and developments in other regions. He served as a Michigan PSC commissioner from 1995 to 2003, during which time he was President of MARC and NARUC. In those roles, he was an active participant in creating the concept and reality of regional state committees.
Betty Ann Kane served on the District of Columbia Public Service Commission for three terms (March 2007 to December 2018), including as Chairman (March 2009 to November 2018), and on the NARUC Board of Directors. She served as chairman of MACRUC and president of the National Regulatory Research Institute. Now a consultant, she has over 40 years of experience in public and private sector energy, finance and management.
DTE Energy’s earnings fell last quarter despite gains for its electric business, the company said Monday during a call highlighting its recent push to reach zero carbon emissions by 2050.
