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.
| PJM
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.
| PJM
“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.
| PJM
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.
Vistra Energy has approached Dynegy regarding a potential takeover that would create the nation’s largest independent power producer with more than 46 GW of capacity, TheWall Street Journalreported Friday.
The Journal, citing unnamed sources, said the two Texas companies are in preliminary talks, but there is no guarantee the deal would go through.
Luminant, Dallas-based Vistra’s competitive generation arm, has 16,760 MW of capacity in Texas. Houston-based Dynegy operates about 31,400 MW of generation in the Northeast, Mid-Atlantic and Midwest (including almost 1,800 MW from plants in which it shares ownership).
Lamar Power Plant | Luminant
A Luminant-Dynegy combination would own almost 46,400 MW alone, surpassing NRG Energy, which claims to be “#1 in competitive generation” with 45,909 MW of net capacity in 29 states, including 1,120 MW of nameplate wind and solar.
The takeover would expand Vistra’s footprint beyond Texas, which saw record low wholesale prices last year. However, to do so, it would have to absorb Dynegy debt said to be about $9 billion, much of it incurred in recent years.
Dynegy entered the ERCOT market in February 2016, when it completed an acquisition of ENGIE’s U.S. power plants for $3.3 billion with private equity firm Energy Capital Partners. (See Dynegy, Energy Capital to Buy 8.7 GW in $3.3B Deal.)
ERCOT represents 15% of Dynegy’s capacity, which is dominated by PJM (43%). A combined Luminant and Dynegy would own almost 21.5 GW in ERCOT — about 45% of the company’s total — while reducing PJM’s share of the total to 29%.
Both Dynegy and Luminant have dealt with Chapter 11 bankruptcy in recent years. Dynegy filed and emerged from bankruptcy protection in 2012 after a failed takeover bid by private-equity firm Blackstone Group. Vistra is the new name for the generation and retail spinoff of Energy Future Holdings, which has been in bankruptcy court since 2014. (See TXU Energy, Luminant Rebrand as Vistra Energy.)
Vistra’s restructuring eliminated more than $33 billion in EFH debt, putting the company into a position where it could suggest an acquisition to Dynegy. According to the Journal, Vistra had only $4.5 billion in debt as of March.
Both companies also have retail businesses. Dynegy has about 963,000 residential customers in Illinois, Ohio and Pennsylvania, while Vistra’s TXU Energy provides energy to approximately 1.7 million residential and business customers in Texas’ deregulated market.
Vistra shares, which started trading on the New York Stock Exchange on May 11, dropped as low as $14.50 Friday but recovered to close at $15.04, down 21 cents (-1.4%). Dynegy shares opened Friday at $9.24 and finished at $9.12; the company’s stock has lost almost 75% in value since June 2014, when it stood at $36/share.
Meanwhile, shares of IPP Calpine, which owns 25,908 MW of generation, have risen by more than a third since the Journal reported May 10 that it was considering a sale.
NYISO’s Power Trends 2017 report shows an electric system of flat peak demand adapting under pressure from both public policy requirements and changes in consumption patterns. However, stark regional differences make the ISO “a tale of two grids,” CEO Brad Jones said in a media briefing on the annual report May 18.
“Not surprisingly, there are distinct differences between downstate and upstate in terms of power resources and consumer demand,” Jones said. “We have high demand and a concentration of fossil fuel generation downstate, while upstate has an abundance of clean energy resources and very low demand.”
The report, which is based on data from the ISO’s 2017 Load & Capacity Data report, or “Gold Book,” also highlights the emergence of distributed energy resources, which, in addition to serving the owners’ needs, can also provide benefits to the larger wholesale market.
The report forecasts peak demand in New York to grow at an annual average rate of 0.07% from 2017 through 2027, a decrease from the 0.83% annual growth projected in 2014 and the 0.21% predicted in 2016. Absent the impacts of energy-efficiency programs and DER, the 2017 peak demand growth rate is 0.73%.
Energy Efficiency and DER Change the Grid
The report projects energy efficiency will reduce New York’s peak demand by 230 MW in 2017 and by 1,721 MW in 2027 with annual energy usage cut by 1,330 GWh in 2017 and 2,533 GWh in 2027.
| NYISO 2017 Power Trends Report
NYISO projects distributed solar resources in New York to reduce peak demand by 450 MW in 2017 and by 1,176 MW in 2027, and to lower annual energy usage by 1,845 GWh in 2017 and by 5,324 GWh in 2027. Other behind-the-meter resources may reduce peak demand by 233 MW in 2017 and by 375 MW in 2027, while possibly cutting annual energy usage by 1,584 GWh in 2017.
Pricing Carbon to Reduce Emissions
Jones said that at FERC’s May 1-2 technical conference on how to integrate state policy with wholesale electric markets, “there was a consensus that did emerge at times from the diverse interests [on] the need to price carbon in the wholesale markets.”
“This is good news, as we have already been looking at that very issue,” Jones said. “A study is underway … and the Public Service Commission and the [Department of Environmental Conservation] have both expressed a willingness to consider those options with us.” (See Carbon Adder to Test FERC’s Independence, IPPNY Panelists Say.)
Since 2000, private power producers and public power authorities have added 11,733 MW of new generating capacity in New York, or approximately 30% of the state’s current generation. The report says more than 80% of that new generation is in southern and eastern New York, where power demand is greatest.
| NYISO 2017 Power Trends Report
Jones said New York’s wholesale market design, which includes locational-based pricing and regional capacity requirements, is encouraging investment in areas where the demand for electricity is highest. He also said that energy efficiency and market improvements have saved $7.8 billion in New York since 2000.
Divide Between Assessment and Planning
NYISO Executive Vice President Richard Dewey took over the report briefing for Jones, who had to leave. RTO Insider asked Dewey about recommendations to improve NYISO’s energy market made the previous day by the grid operator’s Market Monitoring Unit while presenting the 2016 State of the Market report to the Business Issues Committee. (See Gas Price Spreads Made NYC Generation More Economic in 2016.)
In suggesting improvements, how closely had the MMU worked with The Brattle Group, which is conducting the carbon-pricing study referred to by Jones?
“David Patton’s [of Potomac Economics and head of the MMU] responsibilities under our Tariff and what he’s attempting to provide in a State of the Market report is essentially an economic assessment of the market functions themselves and how efficiently they’re working, how effective they are and how fair they are,” Dewey said. “It’s less about a forward projection of other forces that might cause us to want to upgrade either the rules within our market or how we operate the grid. It’s probably premature right now to have a tight intersection between the State of the Market that David Patton does and some of this forward-looking work.”
NextEra Energy’s bid to acquire Texas utility Oncor has failed to gain traction with state regulators, who said Thursday they have not changed their minds about rejecting the Florida company’s purchase.
The Public Utility Commission briefly considered NextEra’s request for a rehearing before deciding to postpone final action until it meets on June 7, allowing time to review reply briefs due May 23.
“I haven’t changed my decision on their motion,” said Commissioner Brandy Marty Marquez, saying she would keep an “open mind” pending the reply briefs.
“I, too, remain unpersuaded at the time by their substantive arguments,” Commissioner Ken Anderson said. “I’m inclined to believe our original decision was the correct one.”
The PUC rejected NextEra’s $18.7 billion proposal last month, finding the acquisition not to be in the public interest because the risks outweighed the promised benefits. NextEra argued the commission went beyond the scope of its powers and called the PUC’s order “unprecedented,” asking it for additional time to review the case (Docket 46238). (See NextEra’s Rejected Oncor Bid Gets Second Look.)
Anderson said after reviewing NextEra’s arguments and an amicus brief filed by Oncor’s bankrupt parent, Energy Future Holdings, he was convinced the PUC has jurisdiction over the transaction and that NextEra was “legally required to seek our prior approval for the transaction.”
“I see no compelling reason to further delay these proceedings beyond what’s absolutely necessary,” Anderson said.
The commissioner asked staff to prepare an order clarifying some of the provisions in the original order and address the technical errors NextEra pointed to in requesting a rehearing. That order would be adopted June 7, should the PUC not grant a rehearing.
NextEra is liable for a $275 million termination fee should the deal fail for certain reasons.
The PUC last year rejected a previous attempt to acquire Oncor by Dallas-based Hunt Consolidated. Oncor’s future is central to EFH’s bid to exit Chapter 11 bankruptcy, which has now dragged on for three years.
New York hedge fund Elliott Management, a top creditor in EFH, sued the ownership group May 11. The firm said NextEra’s bid for Oncor is unlikely to close, and it requested the bankruptcy court to allow it to propose interim financing and alternative restructuring plans for EFH.
The meeting was the PUC’s first without Donna Nelson, who retired from the commission May 15. Texas Gov. Greg Abbott has yet to announce a replacement, leaving Anderson and Marquez to operate without a chairman.
