ERCOT’s seasonal assessments of resource adequacy (SARA) for the fall and winter predict enough generation available to serve forecasted peaks.
The Texas grid operator’s fall SARA shows 77,289 MW of generation available this October and November, more than enough to meet its expected peak of 49,709 MW.
According to the preliminary winter SARA, ERCOT will have 78,253 MW available to meet a projected peak demand of 57,400 MW from December through February 2016. A final winter assessment with an updated weather forecast is scheduled for release Nov. 3.
ERCOT said it expects reserves to range from about 3,600 MW — should peak demand be significantly higher than expected — to nearly 15,000 MW under expected conditions.
“We’ve captured a wide range of scenarios,” said ERCOT’s Pete Warnken, manager of resource adequacy, in response to RTO Insider. “Based on our most recent scenarios, we feel very comfortable with our forecasts.”
ERCOT said it will “continue to monitor the potential effect of Texas’ future drought conditions on generation capacity and ongoing changes to environmental regulations.”
850 MW Additional Capacity Online
ERCOT has added 850 MW of installed capacity since its preliminary fall assessment was published in May, thanks to a combined-cycle generator and three wind projects. Another 1,058 MW of wind projects have been delayed beyond Oct. 1, and will no longer contribute to the fall’s expected capacity.
ERCOT senior meteorologist Chris Coleman said he expects average fall weather despite unusual weather patterns associated with warm ocean temperatures.
Coleman said El Niño this year could be the strongest since 1997, leading to colder, wetter and cloudier winter weather. He said it could also lead to more wind power generated. ERCOT generates about 1,000 MW of wind power during the winter and exceeds 4,000 MW during the summer.
The peak forecast is based on normal weather conditions for 2002-2013 during peak maintenance periods.
ERCOT’s all-time winter peak of 57,265 MW, set in February 2011, was nearly matched in January 2014. The 2014 conditions are reflected in the extreme scenarios included in the winter assessment.
One megawatt powers about 500 homes in Texas during mild weather conditions and about 200 homes during summer.
VALLEY FORGE, Pa. — Members debated four potential changes to the $1,000/MWh energy offer cap last week at a specially called meeting of the Markets and Reliability Committee, failing to agree on any one — or even which should be the main and alternate proposals.
Further discussion was deferred until Sept. 24, giving stakeholders only a few weeks to reach consensus before the Board of Managers takes the matter into its own hands before winter.
Supporters of an increase in the cap say it is necessary to ensure that gas-fired generators can recover their costs when fuel prices spike during periods of extreme temperatures, such as the 2014 polar vortex.
Direct Energy had kicked off the latest effort to reach agreement in July with its plan to raise the cap to $2,700/MWh for cost-based day-ahead offers and price-based real-time offers. The number is 50% more than the highest offers reported by PJM last winter. PJM said that it would support the Direct Energy proposal. (See PJM Stakeholders Struggle for Consensus on Offer Cap.)
Joe Wadsworth of Vitol reiterated his concern about potential unintended consequences inherent in applying different rules to the day-ahead and real-time markets. “We could be artificially creating arbitrage opportunities,” he said, adding that such a scenario might invite increased scrutiny from FERC enforcement.
“We need to ensure the day-ahead and real-time market parameters are the same whenever we can,” he said.
Jim Jablonski, of the Public Power Association of New Jersey, said that whatever the proposed offer cap is, it’s critical it be able to be supported by data. “We can’t get to FERC and say, ‘Oh, we just doubled the old one.’”
Jablonski asked Direct Energy’s Jeff Whitehead if he could estimate exactly how much uplift a higher cap might eliminate. “I’d love for somebody to say, ‘This is how much,’” he said.
Whitehead responded, “The higher the offer cap, the less uplift we’ll have.”
Steve Lieberman of ODEC called his plan “the only proposal that was a joint effort of load and supply.”
It would allow cost-based offers of up to $1,800/MWh and allow them to set LMPs.
And, he said, “Old Dominion firmly believes in the need for a cap that is the same in both markets.”
The Monitor’s proposal would allow cost-based offers to exceed $1,000/MWh when a unit’s short-run marginal costs exceed that cap. Price-based offers would have to be less than or equal to such cost-based offers. Monitor Joe Bowring said the approach addresses the issue of market power when the overall market is tight.
The P3 proposal was the only one that had not previously been presented.
In making the presentation, David “Scarp” Scarpignato of Calpine said that because generators have a must-offer requirement to enter into the day-ahead market, it’s essential they be able to recover their costs.
“The uplift method is a bad idea,” he said. “It’s unhedgeable, and there’s extra risks added to load prices. If you don’t put them into LMP, you lose a very important market signal.”
In allowing offers to set LMPs, according to the proposal, higher prices incent generators to perform.
Like Lieberman, Scarp said the day-ahead cap must equal the real-time cap. Under his proposal, cost-based offers for both markets would be capped at cost plus 10%; market-based offers would be capped at the higher of $2,700/MW or the cost-based offer.
The proposal also sets penalty factors of $1,350/MW for synchronized or primary reserves, and $750/MW for excess synchronized or primary reserves.
PJM has reduced the number of potential transmission fixes for the AP South/AEP-DOM constraints to six candidates.
Six other projects were eliminated following sensitivity analyses for changes in load forecasts and fuel prices.
The projects remaining cleared the 1.25 benefit-cost ratio under all sensitivities and also reduced both AP South and AEP-DOM congestion in combined 2019 and 2022 simulations.
The six proposals include three by Dominion Resources and one submitted by Dominion High Voltage Holdings and Transource Energy (itself a partnership of American Electric Power and Great Plains Energy). The finalists also include one project each from LS Power and Duke-American Transmission Co. Costs of the projects range from $25 million to $301 million.
The fuel price sensitivity looked at natural gas costs $1/MMBtu higher and lower than the prices assumed in the base case. The load forecast sensitivity included an increase and decrease of 2% in load.
LS Power’s Sharon Segner questioned the planners’ screening. “There’s nothing that puts any kind of weight on the cost side and cost containment,” she said. LS Power’s $48.6 million proposal includes a cost cap.
Paul McGlynn, PJM general manager of system planning, said planners will consider cost certainty in further pruning the list of finalists.
Planners hope to select a winning project in time to include it in the 2015 Regional Transmission Expansion Plan.
Last month, they announced the selection of 11 other market efficiency projects with a combined cost of $59.2 million to address congestion in other areas of the footprint. (See “11 Market Efficiency Projects Selected; 12 still in running for AP South/AEP-DOM,” in PJM TEAC Briefs.) Those projects will be recommended to the PJM Board of Managers in October.
McGlynn noted that the RTO has done relatively few market efficiency projects in the past. “We’re very pleased to be having on the order of a dozen [market efficiency] projects to be taking to the board,” he said.
Planners also will reevaluate nine proposed projects to address constraints on the Loretto-Wilton Center 345-kV line, which caused the COMED locational deliverability area to bind in the 2018/19 Base Residual Auction in August. COMED cleared at $215/MW-day, $50 above the RTO price. (See PJM Capacity Prices Up 37% to $165/MW-day.)
The projects, with costs ranging from $11.5 million to $290 million, fell short of the 1.25 benefit-cost ratio in the original analysis. But one or more could clear the threshold if the analysis shows they can increase COMED’s capacity emergency transfer limit, McGlynn said.
Reliability Projects
The 2015 RTEP also will include reliability projects selected from among 91 proposals — 26 transmission owner upgrades and 64 greenfield projects — made in response to Window 1, which closed July 20. The window covered N-1 and N-1-1 thermal and voltage problems as well as generation deliverability and common mode outage and load deliverability issues.
The proposals range in cost from $13,000 to $167.1 million.
The RTEP recommendations also will include dozens of generation-related network upgrades (see pp. 34-68 of the PJM presentation).
Meanwhile, planners have begun reviewing proposals received in response to Window 2, which closed Sept. 4. The window sought solutions for transmission owner criteria and light load reliability criteria violations.
High Voltage Problem in AEP
Planners are considering more than $51 million in transmission upgrades to address a large increase in the number of high-voltage warnings in the AEP transmission zone and northeastern Mid-Atlantic regions. AEP also has seen a large increase in reactor switching for both low- and high-voltage conditions.
The problems, which generally occur during light load periods, are resulting from changes in dispatch due to new and deactivated generation, reactive support deficiencies and increased line charging from new transmission facilities.
Planners are considering spending $51 million to install a 450-MVAR static VAR compensator at the Jacksons Ferry 765-kV substation and a 300-MVAR shunt line reactor on the Broadford end of the Broadford–Jacksons Ferry 765-kV line in southern AEP.
They’re also planning six new shunt reactor installations in New Jersey, the cost of which is still being finalized.
Pratts Area Update
Planners said they will recommend selection of a Dominion project that requires no new right of way to address reliability problems near Pratts, Va.
PJM staff selected Dominion to build a 230-kV line from the Remington substation to the Gordonsville substation.
Dominion will build a new 230-kV line from the Remington substation to the Gordonsville substation and install a third 230/115-kV transformer at Gordonsville at an estimated cost of $103.7 million.
PJM announced last month it was reconsidering its selection of the Gordonsville-Pratts-Remington transmission upgrade after learning that it will require about 18 miles of new rights of way, far more than initially believed. The proposal from Dominion Resources and FirstEnergy was estimated at $129 million to $164 million.
The Virginia State Corporation Commission, which would have to approve the project, says that existing rights of way should be given priority as the locations for transmission additions.
In response to a question, McGlynn said planners had not independently verified Dominion’s assertion that the new line could be built in the existing 115-kV corridor. “We relied on the work of the entities that proposed the project,” he said.
A representative from Madison County, Va., which had urged PJM to reject the original plan, praised the new solution, saying it was “symmetrical with the identified need and an appropriate fix.” The county had complained that the original project was unnecessarily large for the rural county.
The cold weather temperatures produced by the polar vortex of January 2014 continue to haunt FERC.
The commission has denied another generator’s request for $1.3 million in make-whole payments for natural gas it purchased that was never used during the event, citing rules against retroactive ratemaking (ER15-952).
New Jersey Energy Associates, which owns the 290-MW South River combined-cycle plant, said PJM asked that a planned outage for the plant be canceled so it could be available for dispatch on Jan. 27, 2014. The plant purchased $2.7 million worth of gas, having been assured by PJM that it would be compensated for its fuel costs, according to NJEA. The RTO, however, repeatedly canceled the plant’s scheduled start time, forcing it to sell the gas at a $1.3 million loss.
The claims are similar to those of Duke Energy and Old Dominion Electric Cooperative. During the same week as NJEA’s claim, Duke purchased gas for $12.5 million when PJM said that its Lee plant in Illinois would be needed. The plant was never called on, however, and Duke was forced to sell the gas at a loss of $9.8 million. ODEC complained that PJM canceled multiple dispatches that left gas it had purchased unused and that it was due $15 million. (See Duke, ODEC Denied ‘Stranded’ Gas Compensation.)
FERC, however, remained steadfast on its assertion that these kinds of complaints constitute retroactive ratemaking.
“Ratepayers had not received any prior notice of NJEA’s requested relief, which was sought roughly 12 months after the events in question,” the commission said. “We therefore conclude, as we did in the similar Duke and ODEC cases, that the relief sought by NJEA is prohibited by the filed rate doctrine and rule against retroactive ratemaking.”
FERC, however, did find that NJEA was entitled to recover its start-up costs under PJM’s Tariff. The Tariff allows market participants to recover costs related to the start-up of resources offered in the day-ahead energy market if PJM cancels its selection of those resources. While NJEA did not specify how much they would be allowed to recover under this provision in its complaint, it said “this would only be a fraction of its actual unrecovered costs.”
As he did in the Duke and ODEC cases, Commissioner Philip Moeller dissented. He once again noted that PJM is the only grid operator that does not allow its participants to vary their day-ahead energy market offers by hour or update their offers in real time.
As a result of the Duke and ODEC complaints, FERC found that PJM’s Tariff was potentially unjust and unreasonable in this regard and ordered the RTO to make Tariff changes by Nov. 1. While PJM agreed that changes were needed, and it began the stakeholder process to do so, the RTO told the commission in July that it would need until Nov. 1, 2016, to resolve the numerous questions raised by the changes (EL15-73).
“In light of this delay in reforming PJM’s markets,” Moeller argued, “the majority’s repeated failure to guarantee cost recovery for generators acting in good faith to ensure system reliability may regrettably impact reliability during the approaching winter of 2015-2016.”
BOSTON — New England’s states may have to set aside their self-interests to overcome high energy prices that are slowing the region’s economy, Massachusetts Gov. Charlie Baker told the 2015 ISO-NE Regional Plan meeting on Thursday.
The first-term Republican said the region’s competitive advantages are at risk, citing a “sense of desperation” among his fellow governors over energy costs.
“One of the things that’s going to be most fundamental to our ability to succeed is to develop strategies and plans that can get a lot of people who don’t necessarily agree on things to come together and find a way to put the optimal success of the region above what might be the most optimal solution for any particular player,” he said.
“We don’t believe we can achieve the energy security, competitiveness, reliability and affordability … alone. It’s got to be a regional conversation,” he said.
Massachusetts, Rhode Island and Connecticut agreed earlier this year to seek multi-state, long-term contracts to procure large-scale renewable resources. More problematic is building large, multi-state electric transmission and natural gas pipeline projects.
“I think it’s pretty hard to look at the data and conclude that we won’t need to increase our capacity over time,” Baker said, referring to New England’s increasing reliance on natural gas generation and the fuel shortages that occur in the winter months. (See Dueling Studies Dispute Need for More Pipelines in New England.)
He also endorsed exploring the feasibility of importing more hydropower, which would require expensive power lines. “Canadian hydro has potential to be a significant player in the region,” he said, adding that the decision to proceed will depend on how the projects affect ratepayers. “If it doesn’t make sense, we won’t do it,” he said.
Policy Mandates Sometimes at Odds with Market Forces, Panelists Say
Following the governor’s address, a panel discussed whether the region’s pursuit of public policy initiatives is incompatible with low-cost energy.
Over the past 16 years, panelists said, New England’s energy strategy has often been at cross-purposes. The development of competitive markets, the transition from coal to natural gas generation, the integration of renewables and the need for expensive infrastructure all have made it difficult to keep rates affordable.
“In New England, our representatives have decided that renewable energy is really important, notwithstanding whatever preferences the market may have in its short-term, day-to-day interest,” said Edward Krapels, founder of Anbaric Transmission.
“I see us going down two paths,” he said. “The planning by the ISO to maintain reliability leads you down one path. Actions by the governors to create a clean energy economy take you down a parallel path and the two don’t converge.”
He said the three-state model for procuring renewables is the beginning of that convergence.
Public policy has had to contend with “the historical forces of technology and geology” — cheap natural gas — said Katie Dykes, deputy commissioner for energy at the Connecticut Department of Energy and Environmental Protection.
“This low gas price environment that we’ve had has done more for the fuel mix of this industry than the [Environmental Protection Agency] and the environmental advocates have been able to do over the last several years,” said Bob Hayes, vice president of natural gas trading for Calpine.
But he cautioned that the region’s dependence on liquefied natural gas “for the foreseeable future is a precarious one at best and one that I’d definitely be concerned about.”
Tanya Bodell, executive director of research firm Energyzt, said EPA’s initial draft of the Clean Power Plan was an example of policy ignoring reliability. EPA backed off from its proposed early deadline of 2020, delaying it by two years, after widespread criticism.
“That change was needed to show that your state plan is going to result in a reliable outcome,” she said.
MISO and its wind generators are having trouble getting along.
Just two days after FERC rejected allegations that MISO was blocking a wind farm from exporting power to PJM, the RTO was hit with a new complaint accusing it of giving special treatment to external generators seeking to deliver power into the Midwest.
The disputes have arisen as the RTO is attempting to close a capacity shortage that could arise as soon as 2020.
Acciona Wind Energy USA accused MISO in May of blocking it from selling power into PJM by improperly interpreting a process designed to streamline energy exports.
The company complained that MISO had excluded a portion of its 180-MW Tatanka wind farm’s capacity from participating in its pre-certified path study process, which allows interconnection customers to avoid lengthier studies when MISO evaluates their transmission service requests (TSRs). (See Acciona: MISO Blocking Access to PJM.)
MISO Acted ‘Reasonably’
But FERC ruled Sept. 2 that the claim was without merit, saying that MISO conducted Acciona’s system impact study in accordance with its Tariff and business practice manuals. “We find that MISO reasonably concluded that it was appropriate to deny the TSRs given the lack of available transmission capacity absent upgrades,” the commission ruled (EL15-69).
FERC also rejected the company’s claim that MISO was requiring it to make “several hundred million dollars” of upgrades, saying the estimate appears to include all of the costs of the N. LaCrosse-N. Madison 345-kV multi-value project rather than the “but for” upgrades required for Acciona’s service request.
Two days after FERC’s ruling, three wind generators filed a complaint asking the commission to block MISO from enacting rules that would exempt external generation from having to provide “cash at risk” deposits to enter the definitive planning phase, the final stage of the RTO’s study queue (EL15-99).
EDF Renewable Energy, E.ON Climate & Renewables N.A. and Invenergy said MISO’s external network resource interconnection service (E-NRIS) protocol is unfair to internal generation, which is required to make the M2 milestone payments. MISO won FERC approval for the milestone payments in 2012, arguing that they were necessary to weed out speculative projects, whose withdrawal from the queue results in time-consuming restudies.
‘No Safeguard’
The three companies sought fast-track status for their complaint, saying that MISO plans to add 7 GW of external generation into the queue, which it said could have an “enormous impact.”
“There is no safeguard to protect MISO’s queue management from further delay and restudies (and cascading restudies) if any of the 7 GW of [external projects] withdraws; nor is there any safeguard to protect interconnection customers from shifts in network upgrade costs if any [external] customer withdraws,” the complaint said.
The companies called the M2 milestone payment, which is based on generating capacity and transmission voltage, an “extreme burden,” saying a 150-MW project could be required to put up as much as $1 million.
They filed the complaint after MISO’s Planning Advisory Committee delayed a vote Aug. 19 on a proposal by Wind on the Wires that would have imposed the M2 costs on external generators. (See Interconnection Deposit Proposal Tabled.)
MISO and PAC members agreed to postpone the discussion to the Sept. 16 meeting, the companies said, but MISO later informed members that the E-NRIS protocol is final.
Capacity Worries
MISO is seeking to attract and retain capacity resources to offset retirements of coal-fired generation as a result of federal environmental rules and competition from low-cost natural gas.
In 2014, MISO projected it would face a 2.3-GW capacity shortfall beginning next year. In June, however, the RTO said its newest survey with the Organization of MISO States indicated it will have enough capacity to offset any zonal shortages until 2020. (See MISO Survey: No Shortfall Until 2020.)
VALLEY FORGE, Pa. — Capacity Performance resources cleared at $151.50/MW-day in the transition auction for the 2017/18 delivery year, PJM said Wednesday, calling the results “demonstrably competitive” at nearly $60/MW-day below the RTO’s price cap.
The results meant at least a temporary reprieve for Exelon’s Quad Cities and Byron nuclear plants, which cleared the transition auction after failing to clear in the Base Residual Auction for 2017/18. Exelon said Thursday morning that all of its nuclear plants in PJM cleared in the transition auction and that the company will defer any decisions about the future of Quad Cities and Byron for one year.
PJM held the auction Sept. 3-4 to obtain CP resources for 70% of the updated reliability requirement for 2017/18, procuring its target of about 112,195 MW, said Stu Bresler, senior vice president for markets. The clearing price cap was $210.83/MW-day, or 60% of the net cost of new entry.
Bresler said the results showed “a very steady, very rational progression of clearing prices given the steadily increasing proportion of our reliability requirement that we procured as Capacity Performance for these three delivery years.”
The transition auction for 2017/18, which cleared $17.50/MW-day higher, procured 70% of total requirements. Neither transition auction had locational restraints.
In the Base Residual Auction for 2018/19, where 80% of resources were CP, most of the RTO cleared at $164.77.
New Generation in COMED, ATSI Zones
Total capacity offered into the 2017/18 transition auction was 133,769 MW. Of the capacity that cleared, 102,178 MW represented resources committed in previous auctions that now will be converted to the new product at a higher price.
About 10,000 MW of the CP that cleared were from resources that did not clear in the Base Residual Auction in 2014, less than 9% of the total.
Bresler said most of the newly cleared generation was in the COMED (almost 4,000 MW) and ATSI (more than 2,300 MW) zones.
“I think it was fairly well publicized after the Base Residual Auction for ’17/18 the resources that did not clear,” he said. “It just speaks to those that were available to do so in this particular auction from those zones. And I think that’s what we saw.”
PJM reported that 4,339 MW of nuclear cleared for the first time in the transition auction.
Exelon confirmed that Byron Units 1 and 2 (2,336 MW) and Quad Cities Units 1 and 2 (1,737 MW) in Illinois, which did not clear the BRA for 2017/18, were among the winners this time around. (See How Exelon Won by Losing.)
The company said Thursday that it will continue operating Quad Cities through at least May 2018. Byron is already obligated to operate through May 2019. It said it will bid all its eligible nuclear plants, including Quad Cities, Byron and Three Mile Island into the 2019/20 BRA next year.
“While Quad Cities and Byron remain economically challenged, we are encouraged by the results of the recent capacity auctions. The new market reforms help to recognize the unique value of always-on nuclear power, while preserving the reliability of our electric system,” Exelon CEO Chris Crane said in a statement. “However, these plants are long-lived assets with decades of useful life left, and today’s decision is only a short-term reprieve. Policy reforms are still needed to level the playing field for all forms of clean energy and best position the state of Illinois to meet [the Environmental Protection Agency’s] new carbon reduction rules.”
The company said it will “continue its dialogue” with Illinois policymakers for state support for the nuclear units.
New Coal Also Clears
Some 4,165 MW of coal-fired generation also cleared for the first time in the transition auction.
In total, coal cleared 37,455 MW; gas 35,298 MW; and nuclear 29,970 MW.
Higher percentages of energy efficiency (almost 28%) and demand response (65%) came from new rather than previously cleared resources. Of 700 MW of DR acquired, 455 MW represented new commitments.
“I can’t really speculate on the drivers there,” Bresler said. “My hypothesis, I guess, would be that these demand response providers have since the Base Residual Auction for ’17-18 found additional resources that could provide the Capacity Performance level of reliability and therefore offered those resources into the auction.”
$1.7 Billion Increase
The Base Residual Auction for 2017/18 — held in 2014, before the introduction of the tougher CP requirements — cleared at $120/MW-day in most of PJM, with the PSEG locational deliverability area at $215. (See Capacity Prices Jump Following Rule Changes.)
The incremental cost of the transition auction was $1.7 billion, below the estimate of $3.1 billion to $4.2 billion PJM and the Market Monitor had predicted, Bresler said.
Independent Market Monitor Joe Bowring declined to comment on the results aside from saying that they were consistent with the rules. He said his office is working on a comprehensive report on all three CP auctions.
Walter Hall, of the Maryland Public Service Commission, said his agency is keeping an eye on how the prices will affect consumers. “Obviously, it’s going to increase prices somewhat,” he said. “That is a negative. It is a problem, but it’s a problem we knew was coming.”
Dan Griffiths, executive director for the Consumer Advocates of PJM States, said he still had to review the numbers.
But, he said, “I don’t think our position has changed, that this was an extremely excessive solution to the problems we faced.”
PJM, he said, “never considered the impact on consumers.”
Higher Risks, Rewards
The Capacity Performance construct allows capacity resources to receive higher prices in exchange for taking on stiffer penalties for non-performance.
The transition auctions, part of a five-year shift leading to 100% CP for the 2020/21 delivery year, had been delayed in order to allow DR and energy efficiency resources to participate, per a FERC order.
Under the rules of the transition auctions, participation is optional, and market participants may offer all or part of resources that were committed under the Base Residual Auctions for those years as Capacity Performance resources.
The RTO’s 2018/19 Base Residual Auction, the first BRA under the CP rules, saw prices rise 37% to $164.77/MW-day in most of the RTO, while the ComEd zone broke out at $215 and Eastern MAAC hit $225.42.
CP resources were priced at a $15/MW-day premium to base capacity in most of the RTO. In the winter-peaking PPL LDA, the premium was $90. (See PJM Capacity Prices Up 37% to $165 /MW-day.)
CAMBRIDIGE, Mass. — PJM’s 2016/17 transition auction results were released shortly after the stock market closed at 4 p.m. Monday — coincidentally during an EUCI conference in Cambridge, Mass., that attracted PJM Market Monitor Joe Bowring, PJM Senior Economic Policy Advisor Paul Sotkiewicz and Jim Wilson, a consultant to consumer advocates in the RTO.
Wilson, a featured speaker, reported — critically — on the results shortly after they were released, sparking a lively debate with Sotkiewicz. Bowring, uncharacteristically, declined to offer an opinion.
“Unfortunately, the way [PJM] ran the auction, instead of paying people $10, $20, maybe $30 [per MW-day] to upgrade their capacity commitment to Capacity Performance, they created a new clearing price of $134/MW-day, paid to everybody,” Wilson said.
“Of the 95,000 MW that cleared, almost all of it was in the RTO region and not in [MAAC], and they were able to go from $60 their previous clearing to $134. They basically get a $60 windfall — or about $1.7 billion,” Wilson said, concluding: “Very inefficient.”
That sparked a response from Sotkiewicz, who had appeared on an earlier panel with Bowring — both of them already aware of the results but sworn to secrecy until their release.
Sotkiewicz said that during the January 2014 polar vortex, “a lot of [the high generator outages were] coal resources in the west, gas generators in the west who were behind the [local distribution company] city gate who had no firm transportation to the city gate. Even if they did, they could be curtailed by the LDC. [They] also didn’t have dual-fuel capability.
“So, quite to the contrary, a lot of the problems that we did see were in the west during January. So to say that [the CP acquired was] in the west and it’s useless I think is disingenuous and incorrect.”
Asked for his opinion on the “efficiency” of the auction after the conference ended, Bowring seemed uncharacteristically tongue-tied, pausing and exchanging glances with Sotkiewicz.
“We’ll be doing a report on it fairly soon and have a detailed analysis,” he said finally. “It’s hard to tell just looking at the prices. We reviewed the outcome. The outcome was consistent with the rules.”
The Independent Market Monitor for the Regional Greenhouse Gas Initiative found no evidence of anti-competitive conduct in the CO2 allowance secondary market, according to its “Report on the Secondary Market for RGGI CO2 Allowances: Second Quarter 2015.”
Potomac Economics found the average CO2 allowance futures price was $5.53, 2% higher than in the first quarter and 19% higher than in the second quarter of 2014. Prices ranged between $5.30 and $5.60 from April until Auction 28 in early June, and then prices increased steadily during June and reached $5.80 at the end of the quarter.
The report addresses the period from April to June 2015. It is based on data reported to the Commodity Futures Trading Commission and the Intercontinental Exchange, as well as other data.
Consumer Agency Objects to IPL’s Payments to Parent
The Office of Utility Consumer Counselor has asked regulators to deny Indianapolis Power & Light’s 5.6% rate hike request that would generate $68 million more per year, saying IPL deserves only a fraction of that — just $6 million more a year.
The state agency representing consumers alleges the utility has given lip service to asset management while sending $507 million in dividends to parent AES between 2010 and 2014. Since 2010 there have been 14 fires or explosions of IPL equipment, including some events that launched manhole covers into the air in crowded downtown Indianapolis.
The consumer advocate told the Utility Regulatory Commission it doesn’t think IPL has done enough to improve maintenance of its system. IPL countered that it has made numerous upgrades, including locks to keep manhole covers earthbound. IPL has not had a rate case since 1995.
Local Officials Shoot Down Black Hawk County Wind Project
The Black Hawk County Board of Adjustment last week rejected a proposed wind farm, citing residents’ concerns about health, decreased property values and dangers to wildlife.
An attorney for the project’s developers, Optimum Renewables, said there was no evidence that industrial turbines could endanger people or wildlife and said the harm to eagles and birds was exaggerated.
Co-op Rolls over on Solar Fee After Customers Complain
Pella Cooperative Electric is withdrawing its plan to charge customers with solar panels an extra $57.50/month after the plan touched off a firestorm of complaints. Pella notified the state Utilities Board that it was withdrawing the tariff it had filed earlier this year.
All Pella residential customers currently pay a $27.50 fixed monthly fee, and the co-op had wanted to increase that fee to $85 for solar customers. Pella maintained the fee was a fair way to assign costs of operating its system to users. “We have decided to withdraw the proposed increase on the facility charge for members who own or lease distributed generation until such time that we can better educate our members and the community as to the fair and equitable recovery of fixed costs,” it said.
Solar customers rejoiced. “It kinda made my day,” hog farmer Bryce Engbers said. He added he would have taken the solar arrays off his barns rather than pay the increased fee.
By a 4-1 vote, the Public Service Commission approved a merger of Entergy Louisiana and Entergy Gulf States Louisiana. Company officials said the merger of the Entergy subsidiaries will result in up to $140 million in consumer benefits over the next nine years, including $107 million in bill credits.
The lone dissent was Commissioner Foster Campbell, who said he thought it unfair that residents and customers in the northern part of Louisiana will now be charged to help repair equipment damaged by storms that hit the southern Gulf Coast side of the state included in the Entergy Gulf States service territory.
Entergy Louisiana has about 700,000 customers. Entergy Gulf States Louisiana has about 400,000 electric and 93,000 gas customers.
Despite prodding from the state Commerce Department, Xcel Energy has approved just one community solar garden project, which has not yet been built.
The state issued a 2013 mandate to encourage development of community solar. Utility companies need to review and approve each proposed solar facility, and Xcel is currently reviewing 1,100 solar facilities.
Sunrise Energy Ventures, a Minnetonka-based solar developer, complained to state regulators about Xcel’s delay in approving its proposal. SunShare, another community solar developer, and Sunrise each have submitted plans to build 100 MW of solar gardens that collectively would serve more than 30,000 Xcel customers.
The Borough Council of Bloomingdale has introduced an ordinance that would prohibit unregulated pipelines from being built or operated in the borough, a move to discourage the Pilgrim Pipeline from locating within municipal boundaries.
The borough and its residents have been actively fighting construction of the proposed Pilgrim Pipeline, a dual, 178-mile petroleum pipeline that would carry crude oil from a rail terminal in Albany, N.Y., southward to a refinery in Linden, N.J., and refined products back to Albany. The pipeline would replace Hudson River barges, which now move most of those products.
As a petroleum pipeline, the Pilgrim project is not subject to approval by FERC.
Shale wells in the state produced record amounts of oil and natural gas in the second quarter of this year, the state Department of Natural Resources reported last week.
The state reported that more than 10 million barrels of oil and 405 billion cubic feet of natural gas were produced. During the same period in 2014, wells produced about 4.4 million barrels of oil and 156 billion cubic feet of natural gas.
Clean Air Council Suing Sunoco over Eminent Domain Use
The environmental group Clean Air Council is suing the developers of a planned 350-mile natural gas liquids pipeline in the state in an attempt to block it from invoking eminent domain to gain access to properties owned by uncooperative landowners.
The group argues that Sunoco Logistics Partners, developers of the planned Mariner East 2 pipeline, is not a public utility corporation and cannot invoke eminent domain. But the Public Utility Commission has ruled that the partnership’s subsidiary, Sunoco Pipeline, is a public utility, which Sunoco maintains gives it the authority to acquire easements through eminent domain.
Capital spending to comply with the Obama administration’s environmental regulations is dinging the credit outlook for Alliant Energy, parent company of Wisconsin Power and Light and Interstate Power and Light in Cedar Rapids, Iowa.
Moody’s Investors Service has changed its outlook for Alliant to negative from stable. “The negative outlook on the Alliant family’s ratings reflects financial metrics that are weak for their ratings and likely to deteriorate over the next few years as its utility subsidiaries incur incremental debt to finance their extensive, multi-year capital expenditure plans,” analyst Lesley Ritter said. If trends continue, Moody’s said, Alliant’s A3 senior secured rating “would likely be more appropriately reflected in a Baa1 rating.”
Since 2011 Alliant has invested $1 billion in environmental retrofits and is projected to spend up to $1.8 billion more to build gas-fired generating units to replace aging coal and gas units.
DTE Energy is planning to build a 2,800-panel solar farm in Ypsilanti, Mich., by the end of next year. The 800-kW facility would power about 150 homes.
DTE says it’s the largest solar developer in Michigan, with 10 MW from 22 sites in the southeast part of the state. The utility said it has now met a state-mandated renewable portfolio standard.
The company did not release the estimated cost of the Ypsilanti project.
Duke Energy’s South Carolina Transmission Project Draws Angry Opponents
A Duke Energy proposal to build a 45-mile transmission line and a new substation in South Carolina to serve growing demand in western North Carolina drew about 800 people to a public hearing.
Most of the speakers at the South Carolina Public Service Commission’s hearing oppose the project. Their objections include the line’s location, the technique or type of transmission line or the very fact of its planned existence.
Bill Mills of Caroland Farms in South Carolina said he has studied all of the options and concluded that “the best solution for the Carolinas is to have this project canceled.”
Philadelphia Businessmen Buy Retired Exelon Plant for Hotel Project
Two Philadelphia businessmen, operating under the moniker Delaware Station LLC, have put down $3 million for the old Delaware Generating Station, formerly operated by Philadelphia Electric Co. They hope to convert the 16-acre property on the Delaware River to one or more hotels, as well as a shopping and catering complex.
Joseph Volpe and Bart Blatstein are the listed owners. Although there remain some small gas-fired turbines on the site, the main generating equipment at the station was retired decades ago.
FirstEnergy Starts Demolishing Cleveland’s Lake Shore Plant
FirstEnergy has begun tearing down its retired Lake Shore Generating Station in Cleveland, a process that is expected to take about 16 months. The first steps are a full site survey and the demolition of several smaller outbuildings.
The former coal-fired power plant went into service in 1911 and was officially retired earlier this year. FirstEnergy plans to retain the property for alternative uses, a company spokeswoman said. While all generating equipment will be removed, some transmission equipment will remain on the site.
BP restarted a crude distillation unit at its giant Indiana refinery near Chicago last week, a move that is expected to put the brakes on spiking gasoline prices in the Midwest.
The unit at the Whiting, Ind., refinery was shut down Aug. 8 for repairs, which took longer than expected. The extended outage of the 413,500-barrel-per-day refinery, BP’s largest in America, caused fuel shortages that sent pump prices skyward.
Dominion Resources, owner of Millstone Station nuclear plant, has reached a settlement with the Nuclear Regulatory Commission for its decision to halt the use of a safety-related pump in the event of a severe accident.
NRC on Thursday cited a “willful violation” for changes Dominion made without regulatory approval at its Millstone Unit 2 plant in Waterford, Conn. A Millstone spokesman said Dominion does not agree that the violation was deliberate.
Dominion agreed to change plant procedures governing the operation and testing of the charging pumps and provide complete and accurate information. Regulators said they became aware in September 2011 that Dominion submitted requests for approval of changes to the Unit 2 operating license that were incomplete and inaccurate.
ERCOT said it expects reserves to range from about 3,600 MW — should peak demand be significantly higher than expected — to nearly 15,000 MW under expected conditions.
