The rush to build new generation in PJM might be over, if analysts are correctly reading the tea leaves of yesterday’s PJM capacity auction results.
Base Residual Auction prices for Delivery Year 2020/21 fell to $76.53/MW-day in most of the RTO, down from $100 last year. ComEd dropped to $188.12 from $202.77, and MAAC, which cleared with the RTO at $100 last year, dropped to $86.04.
The only areas that saw price increases were EMAAC, which jumped to $187.87 from less than $120 last year, and Duke Ohio-Kentucky, which cleared at $130 this year after pricing with the RTO last year. (See Capacity Prices down in Most of PJM in 1st Year of 100% CP.)
“The silver lining here appears to be a meaningful slowdown in new capacity clearing the auction,” UBS analyst Julien Dumoulin-Smith wrote in a note published Wednesday. “While it’s been years that many generators have been speculating on just when the flow of new units would slow, this appears it.”
| PJM
Less than 3,200 MW of new generation and uprates offered and just 2,824 MW cleared. Both results are down approximately 50% from last year’s auction. Clearing prices for 2020/21 ranged from only 26 to 66% of the net cost of new entry.
“To this end, we see the latest capacity prices and challenges in the debt markets as stymying any future efforts despite a clear backlog of future proposed plants,” he wrote. “We believe the market for new capacity is largely exhausted.”
Capitalizing on cheap fuel caused by an abundance of production in the Marcellus and Utica shale plays and pipeline constraints that limited takeaway capacity, developers flooded the market in recent years with new, highly efficient gas units that have depressed capacity and energy market prices. Low fuel prices persist, but the spark spread might not be as attractive anymore.
“I don’t see any economic justification for bringing a new power plant online” in these market conditions, ICF’s George Katsigiannakis said in an interview. “You start questioning what was driving all those builds: it was economics or it was just irrational expectations?”
Going forward, he said, “the market is going to rationalize and provide better returns,” but that will require unit retirements to reduce the excess capacity. With the onset of governmental initiatives to save certain units for socio-economic reasons, such as the zero-emissions credits passed last year in Illinois, and promote construction of others, such as renewable energy credits for solar and wind projects is several states, Katsigiannakis said “one of the most important issues” is how the oversupply will be curtailed.
“The intervention of state policies on the capacity market … how they can do it so they will not break down the market, is a different question,” he said.
Dumoulin-Smith agreed that he doesn’t “see any obvious easy fixes to improve prices” and that retirements appear to be a waiting game.
“The question is increasingly when will retirements materialize given the lower prices? We think any number of large legacy coal plants could see further pressure in [Pennsylvania and Ohio],” he wrote. “Even fully compliant larger plants could be at very clear risk across any part of the RTO footprint.”
He identified Talen Energy’s Susquehanna nuclear plant and Exelon’s Three Mile Island — which failed to clear the last three auctions — as potential casualties. He said Dynegy’s and FirstEnergy Solutions’ generation also is at risk.
Alternatively, he saw Public Service Enterprise Group, Calpine and Exelon as potential winners from the BRA, with their units concentrated in the higher-clearing locational deliverability areas.
Katsigiannakis said the “big surprise” was how much demand response was able to hang on despite the increased commitment demands of 100% Capacity Performance. He had expected DR to drop by about half from 10,348 MW to approximately 6,000, as that’s how much had year-round capability in last year’s auction. Instead, 7,532 MW cleared.
He said he’ll need to analyze the situation further to understand why so much additional DR was able to clear.
WASHINGTON — Pennsylvania regulator Robert Powelson and Neil Chatterjee, senior energy policy adviser to Senate Majority Leader Mitch McConnell (R-Ky.), received a mostly friendly reception Thursday at their Senate confirmation hearings to fill two Republican vacancies on FERC.
Aside from several interruptions by anti-pipeline activists, the two-hour hearing before the Senate Energy and Natural Resources Committee was largely uneventful with no obvious stumbles by the nominees nor attacks by senators.
The tenor of the hearing suggested Powelson and Chatterjee should have no problem winning confirmation in the Republican-controlled Senate to restore the commission’s quorum, which was lost in February with the resignation of former Chairman Norman Bay.
Powelson and Chatterjee, who are seeking terms expiring in 2020 and 2021, respectively, testified along with Dan Brouillette, President Trump’s nominee to be deputy secretary of energy.
Each nimbly tap danced in response to questions on senators’ pet concerns — favored Department of Energy labs, pipeline and hydro projects, state incentives to save nuclear generation, the fate of the Yucca Mountain nuclear waste depository — promising to consider the issues but not committing themselves to positions.
Chair Lisa Murkowski (R-Alaska) pledged at the end of the hearing to bring the nominees to a committee vote quickly after they answer any written questions from the senators. “My hope is to be able to advance your names quickly, along with that of [nominee for Interior Department deputy secretary, David Bernhardt], so that we can process these nominees for the FERC, for DOE, for DOI and allow the business to proceed.”
Mild Tone
The mild tone of the questions was a stark contrast to the grilling Bay — a Democrat and former prosecutor — received at his confirmation hearing in 2014, when Republicans attacked his record as chief of FERC enforcement. (See LaFleur Cruises, Bay Bruises in Confirmation Hearing.)
That’s not to say the hearing was devoid of partisanship.
Murkowski blamed Bay for resigning and former President Obama for refusing to fill Republican vacancies on the commission last year (by some accounts, a response to the Senate’s refusal to consider Supreme Court nominee Merrick Garland). “As a result of those factors, this is the first time in 40 years that FERC has lacked a quorum,” she said.
Sen. Al Franken (D-Minn.), sitting in for ranking member Maria Cantwell (D-Wash.), countered that Bay had informed the Trump transition team he would resign if replaced as chair. He noted it took Trump three months to name nominees.
Franken also took the opportunity to criticize Trump’s proposed Energy Department budget cuts and its rollback of the Obama administration’s clean energy and climate policies.
“Both the Department of Energy and the Federal Energy Regulatory Commission can play a key role in the clean energy revolution, or they can hold us back while our international competitors reap the rewards,” he said. “That is the prism through which I will consider the nominees that we hear from today.”
Later, in response to Franken’s question about what needs to be done to allow distributed energy technologies to participate in the markets, Chatterjee pledged: “I’m in favor of markets. I’m in favor of competition. And I’m in favor of technology, particularly technologies of interest to consumers.”
Climate Change Question
Sen. Tammy Duckworth (D-Ill.) asked the nominees whether they believed in manmade climate change.
“I’m not a climate denier,” Powelson responded, adding that “market-based solutions” were adding natural gas and renewables and reducing carbon emissions in Pennsylvania.
Chatterjee — who was central in McConnell’s fight against the EPA Clean Power Plan — said he would insist that any policy to cut carbon emissions not undermine the grid. “The first issue at FERC is to oversee reliability. I think that any policy … that seeks to mitigate carbon emissions, we have to ensure that it not have a negative impact on reliability,” he said.
“The climate is changing and we’re all living here, so it must have some impact,” Brouillette said.
Duckworth also asked the FERC nominees for their position on state energy initiatives, such as Illinois’ zero-emission credits for nuclear plants.
“I’m a state’s rights individual,” said Powelson, adding that “nuclear power is part of our energy mix and we’re going to need it.”
Chatterjee also promised, “I believe in states’ rights.”
Sen. Joe Manchin (D-W.Va.) made his case for a continued role for coal in the nation’s generation portfolio, saying it is an essential part of “baseload power. “All that we’re asking for is a proper mix,” he said. “I’m being told by the utility companies the proper mix isn’t being enforced because of certain conditions and certain requirements that the previous FERC has put on them.
“There’s going to be a fuel of the future, I’m sure in 10 to 20, 30 years from now,” he continued. “But right now we have to use — in the cleanest fashion we can — what we have that we can depend on.”
Responding to Sen. Martin Heinrich’s (D-N.M.) question about the commission’s role in transmission development, Powelson said if confirmed, he wanted to “immediately sit down with our regional transmission organizations and independent system operators and see where the bottlenecks are, what’s working and what’s not working.”
PURPA
Sen. John Barrasso (R-Wyo.) asked the FERC nominees for their views of the Public Utility Regulatory Policies Act, passed in the aftermath of the 1973 oil crisis.
Powelson called PURPA “a 1978 vintage document. It was addressing a scarcity issue … and the generation mix has changed today.” He promised to look at “what’s working with PURPA and what’s not” if confirmed.
“But I say this respectfully, a Congressional review of PURPA — a PURPA 2.0 doctrine — might be part of a potential energy bill.”
Chatterjee echoed Powelson’s sentiments. “Any major changes to PURPA would be made by Congress, and while you have my assurance I would work very seriously on this issue should I be confirmed, I think any major changes need to come from this body and not from FERC,” he said. (See related story, PURPA Critics Call for Reforms.)
Paths to FERC
Powelson, a member of the Pennsylvania Public Utility Commission, is the current president of the National Association of Regulatory Utility Commissioners. “What I learned from my experience at NARUC is what works in Pennsylvania might not work in other jurisdictions and the proud appreciation we each have for our individual states’ rights in supporting our states’ energy policies,” he said in his opening remarks.
Chatterjee, a former lobbyist for the National Rural Electric Cooperative Association, became McConnell’s energy adviser in 2011 after working for two years as a staff aide for the coal state senator. Noting the tradition of bipartisanship and consensus at the commission, he touted his ability to compromise with Democratic senators in pushing through legislation.
“We call Neil ‘the Boxer whisperer’ in my office — a term of endearment, I assure you,” McConnell told the committee in his introduction, referring to Sen. Barbara Boxer (D-Calif.). “His work was key in forging alliances between Sen. Boxer, myself … and others that ultimately resulted in bipartisan agreement.”
Franken said Trump should quickly fill the remaining Republican vacancy and nominate a Democrat to replace Commissioner Colette Honorable, who announced she would not seek a new term when hers expires in June.
Numerous reports have identified Kevin McIntyre, co-head of the energy practice at law firm Jones Day, as the third Republican nominee and likely chairman.
“It is important that we restore the quorum at this commission. But it is equally important that the president nominate two more members to fill the remaining vacancies — one a Democrat, and one Republican — and maintain the party balance that the law requires,” Franken said.
The hearing was interrupted several times by protesters from environmental group Beyond Extreme Energy, who chanted “FERC hurts families” and “Shut FERC down.” The group has used the same modus operandi to disrupt FERC open meetings.
Police removed and arrested four protesters, including Lee Stewart, who had tied himself to a chair and had to be carried out along with it. One demonstrator left behind a noisemaker that filled the hearing room briefly with a piercing shriek until it was removed. “Until Congress investigates the agency’s abuses of power and law, the Senate must not approve new FERC commissioners,” the group said in a statement.
At the end of the hearing, Murkowski praised the nominees’ young children, who sat with their mothers in the front row. “You’ve been extraordinarily well behaved,” she said in an apparent dig at the protesters. “I think you set a fine example for grownups.”
We all follow Elon. (He’s ubiquitous.) Tesla buys — or bails out — SolarCity to create an even grander vision of integrating electric cars, solar panels and batteries.
Huntoon
Next will be Tesla/SolarCity buying SpaceX so the integrated electric cars, solar panels and batteries can be transported to those new Martian communities. All aboard![1]
I wrote before about why Elon’s Powerwall home battery made no sense.[2] Remember Elon saying he had 38,000 orders for the Powerwall 1, with installations to begin in October … of 2015? And announcing a new version, Powerwall 2, last year with twice the specs — but at twice the cost?[3]
What is Tesla actually delivering? From Tesla’s first-quarter 2017 letter to shareholders: “In Q1, we installed 60 MWh of energy storage, including a 52-MWh storage project for Kauai Island Utility Cooperative (KIUC) in Kauai, Hawaii.”
So subtracting the Hawaii project using utility-scale Powerpacks, Tesla installed 8 MWh of Powerwalls and other Powerpacks. If the 8 MWh was all Powerwalls, then worldwide sales of the Powerwall were 571 (8,000 kWh divided by 14 kWh per Powerwall).
That is a pittance.
There’s also a huge reality gap for the combined Powerwall/Powerpack business. In August 2015, Elon said revenue in 2017 for this business would be “probably at least a few billion dollars.”
From Tesla’s first-quarter 10-Q we can determine that its Powerwall/Powerpack gross revenues were $5.244 million. Annualized: $21 million.
Tesla Powerwall on house | Tesla
That’s less than 1% of what Elon claimed they would be two years ago. Maybe the first quarter was anomalous. Maybe not.
The fundamental problems with the Powerwall bear repeating.
As a backup generator, the Powerwall is uneconomic and impractical relative to conventional backup generators. Tesla quietly abandoned the backup version of the Powerwall because it made no sense relative to conventional backup generators.[4]
As a cycling generator, there is no value added where net metering is available, because net metering effectively provides storage for free. Rightly or wrongly, net metering remains widespread in the U.S.
Elon acknowledged the value problem in 2015 in explaining why SolarCity wouldn’t offer the cycling version of Powerwall 1. As Bloomberg headlined in May 2015, “Tesla’s New Battery Doesn’t Work That Well With Solar.”
But later, to justify Tesla buying SolarCity, Elon reversed course, saying battery plus solar is a match made in heaven. Confused? So was I.
Powerwall 2, with or without solar pairing, continues the intractable problem of one foot in the canoe, and one foot in the boat.
As a backup generator, it is uneconomic and limited relative to conventional backup generators.
As a cycling generator with solar, it is uneconomic in comparison with net metering that effectively provides storage for free.
At the end of the day, Powerwall 2’s only hope is the demise of net metering … the net metering that the SolarCity business needs to survive.[5]
Isn’t it ironic?
[Editor’s Note: RTO Insider offered Tesla an opportunity to respond to this column on May 15. Although a company spokeswoman claimed the column contained “multiple inaccuracies” the company had not provided any rebuttal as of deadline.]
Steve Huntoon is a former president of the Energy Bar Association, with 30 years of experience advising and representing energy companies and institutions. He received a B.A. in economics and a J.D. from the University of Virginia. He is the principal in Energy Counsel, LLP, www.energy-counsel.com.
[1]We may want to await proof of concept. As Elon said: “I’d like to die on Mars. Just not on impact.”
Speaking of proof of concept, Elon’s latest and greatest is “Neuralink,” which involves implanting electrodes in the brain to enable communication with computers. My immediate reaction: When you think about the damage hackers can do to your computer, imagine what they can do when they hack into your brain. How much bitcoin ransom is that going to cost?
[3]Speaking of cost, here’s a fun question: What costs more, a Powerwall or the equivalent capacity in rechargeable “D” batteries (yes, those flashlight batteries)? If you answered the D batteries, congratulations. A Powerwall is $6,200 (without installation) with 13.5 kWh of capacity. Rechargeable NiMH D batteries have 11.4 Wh, so it would take 1,184 of them to provide 13.5 kWh of capacity. At $5 per battery, the total cost is $5,920.
[4]Tesla continues to promote the Powerwall as providing cycling and reliable backup power even though it is inherent in cycling that the battery will be partially or fully discharged most of the time. And even if fully charged when a utility outage occurs, the battery supply is of limited duration — unlike natural gas backup generators.
And here’s something to check out: On the order-your-Powerwall page here, https://www.tesla.com/powerwall#design, you can select a two-bedroom home using 20 kWh/day. For the option of supplying the entire home for one day, Tesla recommends one Powerwall. How does a battery with 13.5 kWh maximum usable capacity supply 20 kWh? It must be magic.
Not to mention that just the air conditioner for a two-bedroom house of maybe 1,500 square feet is going to exceed the 5-kW continuous rating of one Powerwall. More Musk magic I suppose.
Texas regulators’ decision on the applicability of state and local right of first refusal (ROFR) laws could influence the selection of who builds more than 20 projects proposed for MISO’s 2017 Transmission Expansion Plan, RTO officials said last week.
MISO has no opinion on whether Texas has a ROFR, but it realizes the outcome of the case will affect next year’s competitive developer selection process, Manager of Competitive Transmission Brian Pedersen told the Planning Advisory Committee on May 17.
The Public Utility Commission of Texas is considering a joint request by Southwestern Public Service and SPP to rule on whether Texas statutes allow ROFRs in areas of the state outside of ERCOT’s footprint (46901). (See Texas PUC Agrees to Take up SPP, SPS Request on ROFR.) SPP claims Texas statute only allows for certificates of convenience and necessity inside ERCOT and says other areas should follow a competitive selection process. SPS, on the other hand, argues for the existence of a ROFR outside ERCOT. The Texas PUC will decide the case on briefs without hearing.
Entergy Texas has submitted 22 possible projects for evaluation and inclusion in MTEP 17, ranging from $300,000 to $47 million, and East Texas Electric Cooperative has submitted seven ranging from $900,000 to $62.5 million. MISO will not make MTEP 17 draft project recommendations until August.
Although federal ROFRs were abolished with FERC’s Order 1000, state and local ROFRs were left standing. Upgrades to existing facilities also are assigned to incumbent transmission owners.
Last year, the lone market efficiency project in MTEP 2016 — the $80.9 million Huntley-Wilmarth 345-kV line in Minnesota — would have been opened to competitive bidding save for the state’s ROFR statute. At the time, some stakeholders wrote a letter encouraging MISO to open the project to bidding. (See MISO Board Approves MTEP 16’s $2.7B in Tx Projects.)
Higher Cost Threshold for Competitive Projects?
Meanwhile, stakeholders in MISO’s Competitive Transmission Task Team are debating if the RTO should raise the $5 million cost threshold for opening market efficiency projects to competition. (The RTO’s threshold for opening multi-value projects to competition is four times higher at $20 million.)
MISO staff posed the question to stakeholders at the May 19 task team meeting, saying inexpensive projects might not attract many bidders or justify the cost of a lengthy evaluation and selection process. Staff imagined a scenario where the RTO would run up a $1 million-plus bill evaluating a dozen or so bids on a mere $5 million market efficiency project.
MISO spent $1.3 million last year to evaluate 12 construction bids in its first competitive transmission process, recovering the entire amount from the submitting developers. (See MISO’s Competitive Tx Evaluation Costs $1.3 Million.)
LS Power’s Sharon Segner said MISO’s concern that lower-cost competitive projects would attract too few bidders to justify a costly, full evaluation process would resolve itself because the RTO’s cost to evaluate just a few bids would be much smaller than sizing up a dozen or so bids. MISO could also forego the cost of evaluation altogether if it received just one bid response from an incumbent developer, Segner said. LS Power won MISO’s first competitively bid project with a $49.8 million proposal for the Duff-Coleman 345-kV transmission project.
Pedersen said he has heard arguments for and against a cost floor from stakeholders.
“There are 48 competitive developers in MISO right now, and we trust they can make decisions on whether to bid for themselves. We were just generally asking stakeholders because there was a concern over the evaluation cost. [Stakeholders] raised that issue from an efficiency standpoint, but if developers want to decide what’s best and [decide against a minimum cost floor], that’s fine too,” Pedersen said.
Stakeholders also discussed whether developers should be able to recoup from ratepayers the costs of submitting bids. Some said the issue should be left to FERC while others said states govern what types of costs developers may recover from ratepayers.
MISO is asking for feedback on how to improve its competitive developer process in the hopes of presenting draft Tariff revisions by July. The RTO agreed in December to consider improvements after it announced the Duff-Coleman developer. (See LS Power Unit Wins MISO’s First Competitive Project.)
Staff of the New York Public Service Commission said Thursday that the state’s utilities have 41 GW of capacity for the summer, more than enough to meet a projected summer peak of 33.2 GW.
| NY Dept. of Public Service 2017 Summer Preparedness Report; May 18, 2017
“We have plenty of reserves, and prices are going to be moderate,” Mike Worden, director of the office of electric, gas and water, said in delivering the New York 2017 Summer Preparedness Report at the commission’s May 18 meeting.
The report forecast capability this summer to be 123.6% of demand. The total capability requirement, including the 18% installed reserve margin, is 39,150 MW.
Commissioner Diane Burman asked Leka Gjonaj, chief of bulk electric systems, if the peak load forecast would change if the economy grew more than expected. He replied that NYISO includes econometrics in its forecasts and they would adjust those values to reflect higher growth rates if necessary.
| NY Dept. of Public Service 2017 Summer Preparedness Report; May 18, 2017
“Peak loads continue to decline, and while we can’t line up the reasons one-on-one … we can point to several things that have contributed to it,” Worden said. “Contributing factors include more energy efficiency, more conservation and more distributed generation, and the positive REV [Reforming the Energy Vision] policies that the commission has enacted over the last three years.”
A three-judge panel for the D.C. Circuit Court of Appeals on Friday reversed a 2015 decision by FERC that prevented a Washington state generating plant from recouping funds from the Bonneville Power Administration even though the commission had ruled that it was entitled to the money.
In 2008, FERC had invoked Section 205 of the Federal Power Act to order TNA Merchant Projects, owner of the 520-MW Chehalis natural gas-fired generator, to refund a portion of the rates it had charged BPA for providing reactive power service. FERC had concluded that Chehalis’ rates were not just and reasonable.
Chehalis Generating Facility | Pacificorp
“Several years later, FERC had second thoughts,” Senior Judge Harry Edwards said in the opinion (TNA Merchant Projects vs. FERC, No. 13-1008). “It determined that Chehalis should not, after all, have been required to pay these funds and held that Chehalis ought to recover funds with interest.”
But BPA, the customer to whom Chehalis had paid the refund, had no interest in voluntarily returning the money. Chehalis sought relief from FERC, seeking an order requiring repayment.
“FERC, however, in a perplexing decision, held that it could not order recoupment because the commission’s refund authority does not extend to exempt public utilities such as the intervenor Bonneville,” Edwards wrote, in an opinion joined by Senior Judge David Sentelle and Judge Nina Pillard.
“We hold that FERC erred when it held that it lacked the authority to grant the order requiring recoupment,” the court said. Section 309 of the Federal Power Act permits FERC to “perform any and all acts … [as may be] necessary or appropriate to carry out [the act’s] provisions,” the court said.
The FPA “clearly affords FERC the authority necessary to make Chehalis whole,” the court said. FERC has considerable latitude “when it is prescribing remedies for violations of the FPA and attempting to undo harms caused by its own mistaken or unlawful acts,” the court said.
The court remanded the case back to FERC to determine whether it should “apportion” its recoupment order. “FERC amply explained why recoupment is justified in this case, but in assessing the equities, the commission did not consider whether something less than full recoupment might be warranted,” the court explained.
TNA sold the Chehalis plant to PacifiCorp in 2008 but retained the right to litigate the case.
2005 Rate Filing
The case had its genesis in 2005, when Chehalis filed a proposed rate schedule for providing BPA with reactive power service. In April 2008, FERC concluded that Chehalis’ rates were excessive and ordered it to make refunds to BPA for billings from August 2005 through September 2006, approximately $2 million.
FERC changed course in October 2013, saying that “its precedents on this point had not been entirely clear and thus stated that its determination … was a prospective policy, inapplicable to Chehalis,” the D.C. Circuit said.
In a July 2015 rehearing order, FERC said it believed that recoupment would be appropriate because “Chehalis should not be penalized given the need for clarification” of its policies on reactive power. FERC went on to conclude — incorrectly, the court held — that while it would be “appropriate” for Chehalis to recoup the funds, FERC lacked authority to order BPA to pay.
A BPA spokesman said it was reviewing the order to determine whether to seek rehearing.
“In the meantime, it is worth noting that FERC’s original ruling that the charged rate was unjust and unreasonable was never challenged and has not been overturned,” spokesman Mike Hansen said. “BPA estimates that the rate in question was over 250% of what a just and reasonable rate should have been. If the court’s ruling stands, the matter returns to FERC to ‘balance the equities’ between Bonneville’s rate payers … and TNA Merchant.”
The RTO Insider Top 30 got off to a good start in 2017, with more than two-thirds of companies posting year-over-year revenue and net income increases in the first quarter. All but three were profitable in the quarter.
Collective net income for the Top 30 rose 30% to $9.84 billion on a 6.3% increase in revenue, to $81.81 billion.
NRG Energy and Exelon, which are on opposite sides of the debate over subsidies for nuclear plants, had notable —though notably different — quarters.
NRG was the worst performer in the quarter, losing $203 million after earning $47 million a year earlier. Its revenue fell 14.6% from $3.23 billion to $2.76 billion. The other companies recording losses were Calpine, which lost $52 million and has reportedly hired investment bankers to shop the company, and Great Plains Energy, which lost $9.6 million during a quarter in which its bid to acquire Westar Energy was rejected by Kansas regulators. (See Westar Shares Fall as Kansas Regulators Block Great Plains Deal.)
CEO Mauricio Gutierrez attributed three-quarters of NRG’s earnings decrease to the roll-off of expensive hedges that it executed after the so-called “polar vortex” of 2014, lower capacity revenues in the East and a few one-time items. (See Generation Woes Drive Down NRG Q1 Earnings.) The company’s revenue drop was largely attributed to a fall in its generation revenue to $1.34 billion from $1.7 billion.
Company
Market Cap ($ billions)
Revenue Q1 2017 ($ billions)
% change vs. 2016
Net income Q1 2017 ($ millions)
% change vs. 2016
NextEra Energy Inc
$64.25
$3.97
4%
$1,591.00
143%
Duke Energy Corp
$58.35
$5.73
7%
$717.00
3%
Dominion Resources Inc
$49.43
$3.38
16%
$632.00
21%
American Electric Power Co Inc
$33.79
$3.93
-3%
$594.20
18%
PG&E Corp.
$33.49
$4.27
7%
$579.00
426%
Exelon Corp
$32.47
$8.76
16%
$981.00
698%
Berkshire Hathaway Energy Co
NA
$4.17
3%
$563.00
14%
Sempra Energy
$27.72
$3.03
16%
$441.00
25%
PPL Corp
$26.52
$1.95
-3%
$403.00
-16%
Edison International
$25.48
$2.46
1%
$392.00
28%
Consolidated Edison Inc
$24.54
$3.23
2%
$388.00
25%
Xcel Energy Inc
$23.28
$2.95
6%
$239.28
-1%
Public Service Enterprise Group Inc
$22.26
$2.59
-1%
$114.00
-76%
Wec Energy Group
$19.25
$2.30
5%
$356.90
3%
Eversource Energy
$19.05
$2.11
2%
$261.34
6%
DTE Energy Co
$19.02
$3.24
26%
$394.00
64%
Avangrid
$13.63
$1.76
5%
$239.00
13%
Entergy Corp
$13.58
$2.59
-1%
$86.05
-63%
Ameren Corp
$13.49
$1.51
6%
$102.00
-3%
CMS Energy Corp
$12.91
$1.83
2%
$199.00
21%
FirstEnergy Corp
$12.53
$3.55
-8%
$205.00
-38%
Centerpoint Energy Inc
$11.84
$2.74
38%
$192.00
25%
Pinnacle West Capital Corp
$9.43
$0.68
0%
$23.31
424%
Alliant Energy Corp
$9.06
$0.85
1%
$103.00
4%
NiSource Inc
$8.02
$1.60
11%
$211.30
13%
Westar Energy Inc
$7.37
$0.57
1%
$63.48
-8%
OGE Energy Corp.
$6.83
$0.46
5%
$36.00
43%
Great Plains Energy Inc
$6.15
$0.57
0%
$(9.60)
NA
NRG Energy Inc.
$4.97
$2.76
-15%
$(203.00)
NA
Calpine Corp
$4.96
$2.28
41%
$(52.00)
NA
Total
$81.81
6%
$9,842
30%
NRG is among the entities suing to stop the subsidies for Exelon’s nuclear plants in New York and Illinois. FirstEnergy, which had the second-largest decrease in revenue and fifth-largest decrease in net income among the Top 30, is hoping Ohio joins the states offering subsidies to nuclear generators, but the company said it is planning to divest its merchant generation regardless. (See First Energy Hopeful on State, Federal Support.) FirstEnergy’s revenue fell 8.2% to $3.55 billion in the first quarter, while its net income dropped 37.5% to $205 million.
Exelon posted the largest increase in net income among the Top 30, earning $981 million versus $123 million in Q1 2016. Contributing were its Pepco Holdings Inc. subsidiary, which earned $140 million in the first quarter after losing $309 million a year ago, and Exelon Generation, which posted net income of $423 million, up from $310 million a year earlier. Exelon Generation realized a $226 million (after-tax) “bargain purchase gain” on its acquisition of the James A. FitzPatrick nuclear plant from Entergy.
Pacific Gas and Electric posted the second-largest gain in net income, earning $579 million, compared to $110 million in 2016. Much of the difference was because of one-time expenses the company incurred in the first quarter of 2016: $381 million (pre-tax) that it had to pay out for a wildfire caused by one of its power lines and disallowed capital charges of $87 million (pre-tax) imposed on it by the California Public Utilities Commission for the San Bruno gas pipeline accident.
NextEra Energy had the fourth largest net-income gain in the quarter, earning $1.6 billion from $654 million in the same period last year. A large portion of that came from the sale of its FiberNet telecom subsidiary for $1.5 billion.
CHICAGO — Nearly a century since its formation, PJM assured its members at its Annual Meeting last week that the future is as bright as it’s ever been.
“It’s been 90 years since three utilities — Philadelphia Electric, Pennsylvania Power and Light and Public Service Electric and Gas — decided that forming a power pool would be a more efficient way to meet reserve obligations and share power,” PJM CEO Andy Ott said. “We’ve been delivering value to our members ever since.”
Craig Glazer, PJM’s vice president of federal government policy, breezed through the grid operator’s first 70 years. He noted a New York Times article from 1928 that described the completion of PJM’s original 220-kV transmission ring between the territories of PECO, PPL and PSEG as a “superpower system.”
Former PJM CEOs Phil Harris (1992-2007) and Terry Boston (2008-2015) took it from there.
Harris described the transition from a coalition of regional utilities to an RTO independent of its founding companies. He joined PJM as a contractor in 1992 before being appointed CEO.
The utilities “realized they were going to be in competition one with the other and the solutions would change because there may be winners or losers among the companies,” Harris said. “We wanted to develop something that’s a team without losing the individuality” of each company, he said.
He described several “near misses” on opportunities that could have further transformed PJM. Among those was the creation of an even larger regional power pool that would allow the New York and New England systems to remain separate operationally but form a single market with PJM. One vote in opposition, from General Public Utilities, sank the idea, he said.
(Neither Harris nor any of the other speakers mentioned the circumstances under which he left PJM, resigning after a battle over the independence of the RTO’s Market Monitor, Joe Bowring. See State Regulators: FERC Probe into Bowring Allegations Fell Short.)
While Harris focused on development of the RTO’s structure, Boston’s remarks focused on its employees. He described efforts to entice high-level candidates with advanced electrical engineering degrees to PJM’s suburban Philadelphia headquarters. Now, more than 40% of PJM’s workforce has advanced degrees, he said. He also won board approval for a three-year rotational program for recently graduated engineers to gain experience in all of PJM’s departments before specializing in one.
Ott, who succeeded Boston in 2015, spoke of the support he’s received from the executive team Boston assembled. Ott, who has been at PJM for all of the 20 years it has been an RTO, noted “it feels like only yesterday we were working 23-hour days” to implement locational marginal pricing.
“The markets have evolved significantly over the past 20 years, and I think they will continue to do so,” he said.
PJM also honored its past and current board members, bringing Jean Kinsey (2007-2016), Carolyn Burger (1997-2005) and Richard Lahey (1997-2016) on stage to be recognized. Board Chair Howard Schneider, one of the original board members along with Lahey, acknowledged he will be retiring next year.
During a Members Committee meeting that completed the Annual Meeting, members re-elected incumbent board members Ake Almgren, Susan Riley and Charles Robinson to three-year terms.
PJM executives also provided reviews of the last year. Stu Bresler, senior vice president of operations and markets, said advanced technology has resulted in multiple enhancements, including transmission upgrades to reduce the risk of cascading outages and ways to measure “electrical distance” to ensure units located outside the RTO’s footprint can be relied upon if tied to the system. He said PJM is focused on reducing the day-ahead solution time to less than 2.5 hours in 2017.
Vince Duane, senior vice president of law, compliance and external relations, said the RTO is “probably looking at a suite of responses” to accommodate state public policy initiatives in PJM’s markets. The process is likely to be “politically challenging,” he said, but “there are ways to do it.”
Bowring said that coal remains economical and “a significant part of capacity” going forward as fuel costs continue to vary. LMPs in the first quarter of 2017 averaged $30.38/MWh, 13% higher than in 2016 due primarily to higher fuel prices, he said.
“The relative output of coal and gas, as long as those coal units stay around and are profitable — and many of them are — is going to switch depending on the relative cost of fuel,” he said.
Below is a summary of the issues scheduled to be brought to a vote at the Markets and Reliability Committee on Thursday. The Members Committee held its monthly meeting last week at PJM’s Annual Meeting. (See related coverage, PJM Annual Meeting Celebrates RTO’s First 90 Years.)
Each item is listed by agenda number, description and projected time of discussion, followed by a summary of the issue and links to prior coverage. RTO Insider will be in Wilmington, Del., covering the discussions and votes. See next Tuesday’s newsletter for a full report.
Markets and Reliability Committee
2. PJM Manuals (9:10-9:40)
Members will be asked to endorse the following manual changes:
C. Manual 14D: Generator Operational Requirements. Revisions to develop requirements for solar generation facilities, in compliance with FERC Orders 828 (Requirements for Frequency and Voltage Ride Through Capability of Small Generating Facilities), issued July 21, 2016, and Order 764 (Integration of Variable Energy Resources) issued June 22, 2012. (See FERC Issues Ride-Through Requirement for Small Generators.)
D. Manual 36: System Restoration. Revisions developed in response to a periodic review.
E. Manual 13: Emergency Operations. Attachment E updated with 2017/18 load forecast and Mid-Atlantic load shed allocation information; Attachment F updated with 2017/2018 load shed capabilities and allocation percentages. The data in the attachments affects only transmission owners and has been validated by them.
3. New Black Start Unit Annual Revenue Requirements (9:40-9:55)
Members will be asked to endorse manual and Tariff revisions regarding the annual revenue requirements for new black start units. (See “PJM to Review Black Start Prior to New RFP,” PJM Market Implementation Committee Briefs.)
4. Monthly Meter Correction (9:55-10:10)
Members will be asked to endorse manual revisions to allow for monthly correction of meters for pseudo-tied units and dynamic schedules. (See “Meter Correction Initiative OK’d,” PJM Market Implementation Committee Briefs.)
Members will be asked to endorse a proposed problem statement and issue charge to consider ways to incorporate upgrades approved in the Regional Transmission Expansion Plan in the network model used for FTR auctions. PJM is proposing the initiative out of concern that clearing prices for long-term FTR auctions may not fully reflect future system capabilities.
7. Incremental Auction Senior Task Force (IASTF) Update (10:50-11:00)
Members will be asked to approve an updated charter for the IASTF, which was created in response to a problem statement by Direct Energy that was approved by the MRC in November 2016. The revisions reflect an increase in scope resulting from a problem statement by NRG Energy on replacement capacity that was approved in March 2017. The revisions set a target for completing work and making recommendations to the MRC by January 2018. (See “Stakeholders Approve Variety of Actions,” PJM Markets and Reliability and Members Committees Briefs.)
PJM’s first capacity auction requiring year-round availability saw prices drop by one-quarter in most of the RTO, with only the EMAAC and Duke Ohio-Kentucky regions recording increases.
Base Residual Auction prices fell to $76.53/MW-day in most of the RTO, down from $100 last year. ComEd dropped to $188.12 from $202.77, and MAAC, which cleared with the RTO at $100 last year, dropped to $86.04. EMAAC, which cleared at less than $120 last year, jumped to $187.87, while the Duke region, which did not price separately from the RTO last year, cleared this year at $130.
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This was the first year in which all generation must be Capacity Performance, meaning it’s expected to be available throughout the delivery year and faces stiff penalties for nonperformance.
It was also the first year under relaxed seasonal aggregation rules, which resulted in almost 400 MW of capacity pairing winter generation (mostly wind) with summer solar, demand response and energy efficiency.
With seasonal DR no longer allowed — outside of that matched with other resources through aggregation — price-responsive demand (PRD) participated for the first time in this year’s auction. PJM members committed to 558 MW of demand reductions under PRD.
The auction also followed Illinois’ approval in December of zero-emission credit subsidies for nuclear plants. Exelon said neither its Quad Cities plant in Illinois nor its Three Mile Island nuclear plant in Pennsylvania cleared the auction.
Load Forecast Down
The auction reflected a 2.1% reduction in forecast peak load from last year’s level to 153,915 MW. The reliability requirement was reduced by 2,800 MW from DY 2019/20 because of the lower peak forecast and the PRD elections.
“When the reliability requirement goes down for the same amount of [available] capacity, it’s going to yield a lower clearing price,” said Adam Keech, PJM’s executive director of market operations, in a press conference Tuesday.
PJM acquired 165,109 MW for 2020/21, down about 2,000 MW from last year and providing a 23.3% reserve margin — the highest ever in the 14-year history of the BRA, and well above the required 16.6%.
About 189,918 MW was offered into the BRA, out of about 213,000 MW that was eligible, a decrease of 4,325 MW from last year’s offers.
Keech said the auction will cost load a total of about $7 billion in 2020/21, about the same as for 2019/20.
In total, about 3,144 MW (UCAP) of new generation offered into the auction including uprates, down 3,400 MW from last year. About 2,824 MW of the new generation cleared, mostly natural gas combined cycle and combustion turbines. (See related story, Analysts See End to New Builds in PJM Capacity Results.)
Almost 4,000 MW of capacity imports cleared, up 121 MW (3%) from last year, most of them from west of PJM. Combined with internal generation of almost 152,000 MW, generation made up 94% of the capacity acquired, with DR (7,820 MW) and EE (1,710 MW) making up the balance.
Price Separation
Prices in ComEd, MAAC and EMAAC separated from the rest of the RTO in response to unit retirements and increased transmission congestion in those regions, requiring the acquisition of local generation, said Keech. The Duke region clearing price increased because “we would need to incentivize locational capacity specifically in that area due to retirement,” Keech said.
“We have units that are at financial risk in the area that, if they retire, it could create a reliability issue,” he said.
Although Keech said confidentiality requirements restricted him from going into detail about which units were involved, the creation of the Duke Ohio-Kentucky and Dayton, Ohio, locational deliverability areas were apparently driven by the scheduled 2018 retirements of Dayton Power and Light’s Killen and Stuart coal-fired plants. At 2,700 MW, the plants represent more than half of the capacity in the Dayton LDA.
The Dayton LDA, however, cleared along with the rest of the RTO.
Seasonal Aggregation
Under relaxed rules that allowed aggregation across LDAs, 398 MW of seasonal capacity cleared. PJM filed plans with FERC in October, without stakeholder consensus, to ease restrictions on how seasonal resources can aggregate and offer into the BRA. With FERC lacking a quorum, staff tentatively approved it in March, and PJM quickly established rules in time for the auction. (See PJM Outlines Aggregation Rules for Upcoming Capacity Auction.)
The figure includes intermittent resources that exhibit seasonal performance differences, such as wind, which performs better in winter, and solar, which performs better in summer. It also includes DR resources, many of which are unavailable in the winter.
DR accounted for about 289 MW of the summer seasonal product, while EE accounted for about 103 MW and solar generation the remaining 6 MW. All 398 MW of wind seasonal product was supplied by generation, and Keech said wind accounted for 384 MW of it.
Keech said there were “quite a number” of winter capacity injection rights that didn’t get used as part of the seasonal aggregations.
“Certainly, from our perspective, we would have loved to see some more participation in that area,” he said. “Given that we have 400 MW that we otherwise wouldn’t have ever had, I think that’s successful.”
Renewables as CP
Another 504 MW of wind cleared as CP, for a total of 888 MW of wind (6,828.5 MW nameplate capacity at a 13% capacity factor). That was down about 80 MW from last year’s auction.
An additional 119 MW of solar cleared as CP beyond the seasonal aggregation. The 125-MW total (about 330 MW nameplate at a 38% capacity factor) was down 210 MW from last year’s auction.
Demand Response, EE
The amount of intermittent resources offered as CP dropped by 3,400 MW from last year, while DR offers fell by 2,085 MW compared with total DR offers for 2019/20.
DY 2020/21 will see a 2,816-MW net decrease of DR from 2019/20 to 7,532 MW and a 195-MW increase of EE to 1,710 MW.
The filing to ease the seasonal aggregation rules came after only 6% of DR cleared last year as CP. Stu Bresler, PJM senior vice president of operations and markets, said 4,700 MW of DR could have qualified as CP but didn’t clear economically. This year, 76% of EE and 79% of DR cleared.
Subsidy Impacts
Keech said he couldn’t discuss the specific impacts of the Illinois ZECs on clearing prices.
Aside from Quad Cities and TMI, Exelon’s nuclear plants in PJM did clear, with the exception of Oyster Creek, which did not participate because it is scheduled to retire in 2019.
The company “remains fully committed” to keeping Quad Cities in operation, “provided that [Illinois’] zero-emissions credit program is implemented as expected and provided that Quad Cities is selected to participate,” Joe Dominguez, Exelon’s executive vice president of government and regulatory affairs and public policy, said in a statement. The ZEC program, to be implemented by the Illinois Power Agency, has not yet been implemented.
The company used the results to call for an expansion of ZECs to Pennsylvania, noting that it was the third year in a row that TMI left the capacity auction empty-handed. “Exelon has been working with stakeholders on options for the continued operation of TMI, which has not been profitable in five years.”
Another generator looking for nuclear subsidies is FirstEnergy, which has been pressing Ohio officials for aid for its 889-MW Davis-Besse nuclear plant near Toledo and the 1,231-MW Perry plant near Cleveland. (See FirstEnergy Hopeful on State, Federal Support.)
The company’s hopes suffered a blow last week when the chair of the Ohio House Public Utilities Committee suspended hearings on the subsidy without calling for a vote. “I am not sensing a keen desire on the part of the House members to vote on this and doubt that we will have more hearings in the near future unless something cataclysmic should happen,” The Plain Dealerquoted Chairman William Seitz.
But the auction brought some good news for the company. Asked whether Perry and Besse-Davis cleared the auction, spokesman Doug Colafella responded: “Yes, a portion of all of the units FirstEnergy Solutions bid into the auction cleared.”
Also reporting on its fortunes was Dynegy, which said Wednesday that it cleared 10,217 MW, representing $456 million in revenue at a weighted average of $122.19/MW-day. That included 9,772 MW from the company’s PJM fleet ($124.27/MW-day) and 444 MW exported from MISO ($76.53/MW-day).
Still Getting Gas
Gas-fired units continue to benefit from ongoing pipeline constraints that have built up a glut of natural gas and depressed prices in the Marcellus and Utica shale regions throughout PJM’s footprint. Despite clearing prices of approximately 26 to 66% of the net cost of new entry, the auction attracted 2,350 MW of new gas-fired generation.
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“I think it’s intuitive that that [gas entry] will slow down given that the prices are below” net CONE, Keech said.
Price Responsive Demand
PJM members committed to 558 MW of demand reductions under PRD, with the BGE (330 MW), PEPCO (170 MW) and EMAAC (58 MW) LDAs participating.
Unlike DR, which is counted on the supply side, PRD is deducted from the reliability requirement, shifting the LDAs’ demand curves to the left.
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NRDC Critical
Jennifer Chen of the Natural Resources Defense Council was disappointed that wind, solar and DR resources declined compared to last year and that the RTO “is continuing to rely primarily on fossil fuels and nuclear.” She blamed the “arbitrary” CP rules for creating a “preference” of gas and nuclear over “clean power” and argued that the new seasonal aggregation rules squeeze out many summer-only resources that can’t find winter-only resources to pair with for the auction.
She also criticized PJM for securing too much capacity, saying consumers are paying more than they should pay for reliability.
Predictions
Results largely defied expectations, fueling a recurring complaint among market participants about the market’s volatility.
Earlier this month, ICF analysts Rachel Green, Himanshu Pande and George Katsigiannakis predicted prices would exceed $100/MW-day as the 100% CP requirement offset downward pressure from increased supply and lower demand. They predicted the EMAAC, ComEd and Dayton LDAs would see price separation from the rest of the RTO.
Julien Dumoulin-Smith, an analyst with UBS, predicted in March that the ComEd region would break $200/MW-day, and in April that EMAAC would remain “roughly flat.” He did, however, note changes to transmission accounting that would cause EMAAC to clear separately from the rest of the RTO and cautioned that demand reductions would likely depress clearing prices.
No analysts could be reached Tuesday for comment on the results.
