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.
CAISO stakeholders last week voiced skepticism about the effectiveness of a new ISO initiative to prevent early retirement of unprofitable generators that will be needed to ensure grid reliability as California progresses on its aggressive renewable energy goals.
The ISO wants to limit the scope of its “risk-of-retirement” initiative to improving processes for its existing Capacity Procurement Mechanism (CPM), which includes a set of “backstop” provisions that enable the ISO to bypass its wholesale market to directly compensate generators under exceptional circumstances.
“We’ve had the CPM risk-of-retirement Tariff provisions in place for a number of years, and we’ve heard from suppliers that they think that those provisions are — for lack of a better word — clunky,” Keith Johnson, CAISO manager of infrastructure policy and contracts, said during a May 18 CPM Risk-of-Retirement Process Enhancements working group meeting to kick off the initiative.
Unaddressed Issue?
But some market participants say the initiative will fail to address a looming and critical issue: that CAISO’s energy market can no longer adequately compensate the construction and operation of the kind of resources needed to support the grid as California moves to meet its 50% renewable portfolio standard by 2030.
The effort specifically aims to address the circumstances of gas-fired plants that are not currently needed for resource adequacy (RA) and do not earn enough money in the wholesale market to remain financially viable but will likely be needed in the future as other units shut down because of state environmental standards prohibiting once-through cooling.
CAISO wants to build a clear “bridge” that would provide a needed supply resource with a limited period of out-of-market payments until the plant is able to obtain an RA contract from a load-serving entity.
Under existing rules, only resources not currently under an RA contract are eligible for a CPM risk-of-retirement designation. A resource still under contract must wait until its agreement expires before making an application.
The application must include an offer price as well as an attestation signed by an executive officer stating that the resource is uneconomic and that retirement is inevitable without the CPM designation. Once that information has been submitted, the ISO undertakes a study to determine whether the unit will likely be needed for RA during the compliance period two years out.
Timing Problem
A key problem for resource owners: CAISO cannot initiate its study to determine the need for an individual unit until November of each year, just after all LSEs publish their RA requirements for the following calendar year. That gives a resource just two months’ notice before losing an RA contract, followed by a three- to four-month ISO study and stakeholder comment process, leaving the resource owner in financial limbo for an extended period. Through process changes, the ISO hopes to provide a resource a financial bridge to get from the next year — for which it lost its RA designation — to the following year, when it is assumed to be needed.
Mark Smith, a vice president at Calpine, said that even if the ISO could issue a CPM designation as early as November, it wouldn’t provide his company enough time to weigh the decision of whether to keep operating a potentially money-losing plant.
“We’re making business decisions on maintenance. We’re making business decisions on employment of people. We’re making business decisions that cannot be done in a few weeks or a couple of months’ timeframe,” Smith said. “These are multimillion-dollar assets — sometimes hundreds of millions of dollars.”
Earlier this year, CAISO awarded reliability-must-run designations to two Calpine peaking plants after the company said it would be forced to retire the facilities if required to await a CPM decision next year. (See CAISO RMRs Win Board OK, Stakeholders Critical.)
Calpine sought to extend the operation of its Yuba City peaking plant through a reliability must-run award rather than the risk-of-retirement provision of CAISO’s Capacity Procurement Mechanism. | Calpine
“What we found ourselves in was a situation that the only viable option was to use an RMR contract,” Johnson said. “So what we’re trying to do in this initiative here with CPM is to address at least some of these process enhancements so CPM can be used as, more or less, the first and primary backstop procurement option.”
CAISO won’t produce a proposal on the issue until it receives stakeholder comments after a second working group meeting May 25. Johnson emphasized that the ISO wants the initiative to zero in on the process for applying for a CPM designation — including the timing and deadlines for studies, rather than dealing with the costs or terms of CPM contracts.
Johnson also assured stakeholders that CAISO would not use CPM to circumvent other procedures in place, such as the RA program administered by the California Public Utilities Commission, which relies on ISO studies to determine statewide needs for system, local and flexible capacity carried by the state’s utilities. The ISO’s own RA efforts focus on complementing that program by developing market mechanisms to procure increasing amounts of flexible capacity.
Michele Kito, a PUC regulatory analyst, expressed concern that the ISO would start to use an updated CPM process under more than just “extraordinary circumstances.”
“We don’t envision using this more frequently than we do now, in the sense that it’s really just making the process work better,” Johnson responded. “I mean it’s possible that you might see more CPM risk-of-retirement if more units become at risk of retirement, because — remember — this is really a backstop mechanism.”
While Tyrone Hillman, a principal with Pacific Gas and Electric, said he understood the ISO’s need to narrow the scope of the initiative, he pointed out its overlap with another effort that could allow certain unprofitable generators to temporarily suspend operations short of full retirement. (See CAISO Initiative Could Toss Lifeline to Struggling Generators.)
Johnson acknowledged the “potential” overlap between the two efforts, but said the ISO wanted to keep them separate to ensure the ISO Board of Governors approves at least one of them later this year.
“If one of the initiatives gets bogged down, then hopefully it wouldn’t bog down the other initiative,” Johnson said.
‘Elephant in the Room’
“The elephant in the room is killing me, so I’m going to bring it up,” said Eric Little, manager of wholesale market and greenhouse gas market design at Southern California Edison. “We have to recognize that the state has goals to go to low — if not zero — GHG emissions from the electricity sector.”
Getting there will mean increased reliance on renewable resources, translating into a larger number of market intervals with “very low” to negative prices, Little said.
Prior to the high penetration of solar on the California system, generators without RA contracts could earn sufficient revenues from the energy market, Little said. That opportunity is dwindling.
“So the question in front of us is how to we get from here — where we have been with that environment — to an environment in which we no longer have any thermal resources on the system,” Little said. He joked that California might never achieve that goal if nobody is consuming electricity at all “because the lights are out” because of low system reliability.
“I think recognizing all the different pieces that have to work is important thing,” Little said.
Calpine’s Smith pointed to the “huge shift in pricing dynamics” over the past two years, which leaves peaking units running just 5% of the time and earning just 50 cents/kW-month, too little to cover property taxes, let alone operation and maintenance costs.
“Eric is right. What we need here is a thought-out plan to transition us to the new world, and part of that plan has to involve — at least from Calpine’s perspective — the confirmation that units needed for local reliability are locked in and able to do all the stuff they need to do to manage the transition while the transition occurs,” Smith said.
“That’s way beyond CPM, way beyond the very narrow issue, Keith, that you’ve defined here, but that is the elephant that needs to be addressed.”
The Organization of MISO States has adopted a stricter protocol for entering closed session during board meetings.
OMS will now require requests for closed session be circulated a few days before a meeting with an explanation for the private conversation. If an objection is raised, the OMS Executive Committee will decide by simple majority if the topic deserves closed session treatment. Acceptable closed session topics include personnel and legal matters, discussion of commercially sensitive materials, and issues subject to attorney-client privilege. (See “Closed Session Procedure Outlined,” OMS May Add Voice to Pseudo-Tie Fracas.)
“At least in Wisconsin, we have to assume that meetings are open. … You better have a darn good reason to go closed,” Wisconsin Public Service Commissioner Michael Huebsch said at the May 18 OMS board meeting.
The new rule was approved by acclimation.
OMS President and Indiana Utility Regulatory Commissioner Angela Weber led the move to draft new rules after some organization members requested a closed session in February to discuss MISO and PJM’sFERC filing to implement targeted market efficiency projects. OMS held closed sessions again this spring over the creation of a seams policy document. Neither of the matters warranted closed discussion, Weber said.
MISO May End Automatic Steering Committee Leadership Posts
MISO stakeholders are considering a change to the Stakeholder Governance Guide that could shake up Steering Committee membership, and OMS is telling its members to prepare for a sector vote next month during the RTO’s Board of Directors week.
The vote could allow a Steering Committee leaders to be selected through an independent stakeholder vote.
Under the Stakeholder Governance Guide, the vice chair of the Advisory Committee serves as chair of the Steering Committee, with the Advisory chair serving as the Steering vice chair.
Manitoba Hydro’s Audrey Penner currently serves as the Advisory Committee chair and the Steering Committee’s vice chair; NRG Energy’s Tia Elliott is the Steering Committee chair and Advisory Committee vice chair.
Ted Thomas, chair of the Arkansas Public Service Commission, said OMS members should be prepared for an Advisory Committee vote to change the governance guide at the June 21 meeting in Branson, Mo., although no agenda items are yet listed for the meeting. A vote in favor of severing the Advisory Committee leadership from the Steering Committee leadership might trigger Steering to hold an almost-immediate election for new leadership, as the selection method of its current leadership would no longer be valid, Thomas said.
“Now, generally I think that it is a good idea, and I don’t have any conflict with it. But it might be a problem if the people in those positions have [problems with their own removal]. To me, the juice isn’t worth the squeeze [if there are problems],” Thomas said.
He said he didn’t want the move to create any “dramatic” issues with a sudden change in leadership.
“It’s a dangerous precedent to make it immediate, and just remove the people there,” Huebsch said.
MISO spokesperson Mark Brown confirmed that some stakeholders have “initiated conversations about the idea of having separately elected Steering Committee leadership” but declined to identify who. He said MISO’s Stakeholder Relations team has yet to receive any motions or agenda suggestions for the June Advisory Committee meeting.
CHICAGO — The times, they are a-changing — again. How will companies respond?
Executives from a utility, an independent power producer, a large industrial customer, a municipal power company and a power retailer met in a panel discussion at PJM’s Annual Meeting last week to answer that question. Unsurprisingly, their answers differed based on their role in the markets.
“We are in an energy transition. … Every company in this room is going to have to figure out how to participate in an energy transition, and if we don’t, we’re going to get run over,” said Larry Stalica, president of Linde Energy Services. “I believe there’s enough smart people in this room to figure out how to get from Point A to Point B.”
Linde, whose industrial and medical gas production facilities are big power users, became its own load-serving entity in March 2003. “We realized that these wholesale markets were going to be the key to controlling our costs and making our business successful,” he said. “So we wanted our voice heard.”
His call for leadership was echoed by Marc Gerken, CEO of American Municipal Power. “Don’t be afraid to break something down that isn’t working,” he said. “That’s good leadership.”
He went on to criticize PJM’s consistent tinkering with its market designs. “We get sometimes troubled with all of the changes in the market constructs. It’s tough to follow; it’s tough to keep track of; so we think that there needs to be a little more discipline on that,” he said. “We are a very transmission-dependent utility. We don’t own a lot of transmission [so] we really feel that PJM needs to focus on the reliability aspect. We think that’s your mission.”
Gerken said the competitive transmission process created by FERC’s Order 1000 allows incumbent transmission owners to pad their balance sheets with trumped up costs for supplemental projects. And “we’re just supposed to trust them,” he said.
Calpine CEO Thad Hill said his company has had to “waste” energy in the middle of the day when oversupply causes prices to go negative. “I kid you not,” he said. “I think we’re better than that.”
Direct Energy President John Schultz said weak demand could result in “incumbent market participants really fighting over a shrinking pot” of revenue.
Chris Crane, CEO of Exelon — which is battling court challenges to zero-emission credits for its nuclear plants in New York and Illinois — called on industry members to collaborate on issues, rather than litigate them.
The industry took a wrong turn two decades ago when it decided to divorce environmental and market policy, he said, resulting in renewable energy subsidies that diminish market efficiency.
“It has put us in a very difficult situation where, instead of working together to try to find ways to satisfy the environmental desires of the states, we find ourselves in court fighting over” the impact of state environmental policies on the energy markets, he said.
“Not a place that we should be. It’s a degrading situation. What we should be doing is working together on what’s the market design that [can accommodate] a state [that has] environmental programs that they desire. How do we come up with the market design that is managed at the ISO level that can incorporate that to be fair and equitable? That’s where the focus needs to go.” (See PJM Stakeholders Offer Different Takes on Markets’ Viability.)
He also questioned those who contend end-use customers want more control over their energy usage, as distributed energy resource proponents claim.
“That is where we have to decide — as we’re designing the systems of the future — how much is a trend and how much is a fad,” he said. “We have the job of protecting the customer as things go forward.
“We’re at a place … where things are changing pretty quickly,” Crane said. “As participants in the market, we need to come together. … I would much rather be having conversations with my counterparts here on what we can do constructively to fix the larger problem so we’re not having to put one-on-one Band-Aids on this marketplace.”
