The proposed protocol — which would continue on a smaller scale than the New York-PJM-New York flows of the wheel — has attracted criticism from stakeholders, which continued at last week’s PJM committee meetings. The influence and resiliency of phase angle regulators received some scrutiny from Citigroup Energy’s Barry Trayers at the Operating Committee meeting.
| PJM
“In a way you can kind of be picking winners and losers by adjusting [their] flows,” he said, asking how they had been factored into the grid operators’ guidelines for developing the replacement protocol.
“We consider PAR moves just like switching: a non-cost move that we’ll do prior to redispatching generation,” PJM’s Mike Bryson explained. “If we start running up against some of the either daily or monthly PAR adjustments, we’re going to have to take a step back and say, ‘Are we moving them too often? What’s the impact?’”
One challenge for the new protocol: One of the PARs on the 5018 line at Consolidated Edison’s Ramapo facility is not functional, which limits the ability to export power to NYISO. The grid operators have identified 1,800 MW as the maximum that needs to be available for export to NYISO, but the nonfunctional PAR limits PJM’s export capability to 1,400 MW.
While the future of Con Ed’s PAR has received a lot of discussion from other stakeholders, PJM has not received any details on when or if it will be fixed. One plan under review is to compensate by adjusting flows on the western interconnections across the Pennsylvania-New York border.
PJM and NYISO are currently working on updates to their joint operating agreement, which PJM will present upon completion for stakeholder review. NYISO plans to begin its stakeholder approval process at the end of October and complete it by January, which would allow the grid operators to make a joint filing to FERC later that month.
Stakeholders Urged to Submit Unit-Specific Parameter Adjustments
Generation unit operators have until Feb. 28 to submit adjustments to their unit-specific parameters, but PJM is urging them to begin the process as soon as possible because it can take several weeks.
PJM is aiming to have the status of delivery year 2017/18 adjustment requests posted by April 15. Parameters will be implemented in June. Any adjustments that are already approved remain valid, PJM’s Alpa Jani said, and don’t require resubmittal. Requests will receive a case identification number, with which requesters will be able to look up their current status through the RTO’s online member portal.
eDART Improvements Will Slow in Anticipation of Overhaul
PJM’s eDART system is getting an overhaul to incorporate new functionality, including single sign-on. To allow staff the time necessary to develop the new system, refreshes of the current system will be reduced to only those that are operationally necessary.
What won’t be changing are the business rules, the system interfaces or email notifications, said PJM’s Chidi Ike-Egbuonu. “One thing we can agree on is that it’s going to be a multiyear project; it’s not going to happen overnight,” she said.
PJM Moving Flat-File Data to Data-Management Tool
Raw data files are becoming too cumbersome and are being retired in favor of access through PJM’s Data Miner 2 tool, the RTO’s Thomas Zadlo explained. The tool will allow access to all data that is currently being stored on flat files, including five-minute settlements. Progress on the transition will be shared with stakeholders through PJM’s new Tech Change Forum.
WASHINGTON — “Pernicious subsidy” or “rough justice”?
Audience members got to decide for themselves how to characterize net metering for rooftop solar generation during a debate at the Energy Bar Association’s Mid-Year Energy Forum last week.
Richard L. Roberts, head of the electric group at Steptoe & Johnson, said it’s unfair that rooftop solar owners are paid retail prices as high as $0.13/kWh for the power they inject into the grid while central station generators are paid wholesale rates of about $0.04/kWh.
As a result, a customer whose solar panels generate energy equal to their consumption for the month “pays nothing for their electric service. They pay nothing for the reserves that they’ve been given. They pay nothing for transmission. They pay nothing for distribution. They pay nothing for public purpose programs, all of which go into retail service.”
Scott Hennessey, SolarCity’s regulatory counsel and vice president of policy and electricity markets, responded by citing a Sept. 30 ruling by the Massachusetts Department of Public Utilities last week that he said found rooftop solar provided more benefits than costs to the state’s grid. (See related story, Regulators Reject DER Surcharge in Rate Case.)
Glick | RTO Insider
He dismissed as a “common trope” the notion that rooftop solar is only for the “wealthy and well meaning.” The introduction of smart inverters allows rooftop solar to provide voltage support and other services to the grid, he said, while the introduction of financing options makes it available to the middle class.
Also participating in the discussion — though not staking a position on either extreme — was Mark Glick, administrator for the State Energy Office in Hawaii, a state that has provided a cautionary tale for regulators as generous subsidies have threatened to overwhelm the islands’ grids with solar generation.
Utility-Scale vs. Distributed Solar
Hennessey | RTO Insider
The session, moderated by Caileen Gamache of Chadbourne & Parke and Matthew R. Rudolphi of Duncan, Weinberg, Genzer & Pembroke, also touched on the virtues of distributed versus centralized solar generation.
“The question of whether or not [rooftop solar is] harmful to the grid or harmful to the average consumer I would turn around,” Hennessey said. “When you have infrastructure purchased by a utility and then spread across the entire rate base — with a fat profit, by the way, for the utility — that is a choice made decades in advance — and I think we’ve seen now, not always with the best of foresight,” he said. “Whereas when you have solar and the other distributed energy resources I’ve mentioned, that’s private investment in infrastructure that then benefits everyone around, with less peaking generation required.”
Hennessy said utilities that want to develop large-scale solar should be required to use a nonutility business unit rather than competing with other developers by using the utility’s low cost of capital and other advantages.
“What we’ve found is that every time they have tried that they have failed and they’ve had to close up shop, as [Arizona Public Service] did in Arizona.”
Jurisdictional ‘Mess’
Roberts | RTO Insider
Roberts said the Supreme Court’s FERC v. Electric Power Supply Association ruling, which preserved FERC’s right to regulate demand response, left a “jurisdictional mess” because the commission has no authority over net metering sales. Such sales should be a FERC-regulated wholesale sale under the Public Utility Regulatory Policies Act (PURPA), he said.
Roberts also cited studies showing utility-scale solar is two to three times more efficient than rooftop solar.
The rush to distributed generation could repeat the kind of mistakes California regulators made with the first retail choice program in the 1990s, which resulted in overpayments to qualifying facilities under PURPA and politicized integrated resource processes, he said.
“The goal of grid modernization should be to allow — without preferences or without predetermining who’s the winner and who’s the loser — equal access to all of these forms of technology to compete against each other and then wait and see where the next innovations come from,” he said.
“Nobody knows what the next big technological breakthrough is going to be. It might be large-scale generation, and if we’ve skewed our investments in the grid toward microgrid or small-scale [generation], we could find ourselves once again looking at investments and wondering why we did that.”
Hawaii’s Glick said “there’s no doubt” that utility-scale solar is cheaper than distributed resources. “But ultimately that will change and we have to allow the market to develop while that change occurs,” he said.
CARMEL, Ind. — Reviving his criticism of MISO’s lenient thresholds for uninstructed deviations, the Independent Market Monitor last week presented new data showing the impact of the RTO’s rules.
Market Monitor David Patton told the Oct. 4 Market Subcommittee meeting that slow-ramping units have too much flexibility to deviate from their dispatch instructions — so much so that generators can essentially ignore dispatch signals and not be penalized under MISO’s rules. Currently, generators are flagged if they deviate more than 8% from dispatch instructions for four consecutive intervals.
Under the current rules, generators drag by an average of 65 MW five minutes after receiving their dispatch instructions, and the drag worsens to an average of 314 MW when extrapolated to an hour, Patton said.
Generators are “basically being held harmless for poor performance,” Patton said. “We should not be paying you for refusing to turn on a mill.”
Patton has proposed moving to a system based on ramp rate, setting the threshold at half of the unit’s ramp capability with a cap of 10% of the dispatch level to limit gaming. The rules would make it so that units that are not responding to instructions after 20 minutes would be flagged.
“You can be motionless for 20 minutes before you would be flagged for dragging,” Patton explained. “You have to fail for three consecutive dispatch intervals before you are flagged for that hour.”
| Potomac Economics
Patton also said the proposal would eliminate the incentive to understate a unit’s ramp rate. The current 6-MW floor and 30-MW ceiling would remain.
The Monitor’s suggestion is not new: It first appeared in his 2012 State of the Market report, and it’s been brought up every year since, with Patton expressing disappointment that no progress had been made. (See MISO Monitor Debates Capacity Rules with Board.)
Stakeholders countered that it takes a long time to get large, baseload generators running. Operators will sometimes delay starting up units to make sure the dispatch signal is accurate, they said.
Patton responded that the heart of his suggestion is a “tolerance” that would give generators extra time to respond before they are flagged for dragging. But he said he could do more analysis on the reasons behind start delays.
The Monitor also said his team continues to investigate wind resources, which have larger deviations than any other resource type. “We think there may be economic incentives to over-forecast wind, and wind resources may be deliberately over-forecasting to MISO,” Patton said.
Chad Koch, market strategist for WEC Energy Group, said Patton’s proposal may hurt “fast-moving, accurate machines.” While “big resources move slowly and wind resources are up to the whims of Mother Nature, they should not get free rein,” Koch said.
MISO said an analysis against historical real-time data is needed to understand the impacts of the Monitor’s recommendation before it is adopted. In late spring, the RTO said the scope of the project had delayed its target for implementation to next year. (See “Changes to Uninstructed Deviation Thresholds Longer than Anticipated,” MISO Market Subcommittee Briefs.)
MISO’s John Weissenborn said staff would come back to the Nov. 29 Market Subcommittee meeting with its own proposal. Threshold changes, Weissenborn said, would most likely go into effect by the middle of the second quarter.
CARMEL, Ind. — MISO’s mechanism for allocating charges under its settlement with SPP was certified by a FERC administrative law judge last week (ER14-1736).
MISO has been using a temporary miscellaneous charge based on market load ratio share to collect the $1.33 million a month it is paying SPP until February for flows over 1,000 MW passing through MISO’s North-South interface. Under a settlement reached with its stakeholders, MISO will use a new, modified market load ratio share basis to allocate those costs. This method also applies to the $16 million it paid from Jan. 29, 2014, to Jan. 31, 2016, but that amount won’t be subject to resettlements, MISO Director of Market Services John Weissenborn told the Market Subcommittee on Oct. 4.
From Feb. 1, 2016, to Jan. 31, 2021, MISO will use a transitional, hybrid method, with a continuously declining percentage of the costs allocated through the new load ratio share calculation and an increasing amount through a flow-based benefits allocation methodology.
Weissenborn said the RTO will continue to allocate the costs under the current method until FERC accepts the settlement agreement and accompanying Tariff language. After approval, MISO can begin resettlement for costs from Feb. 1, 2016, and beyond.
“We can almost anticipate two resettlements: one to true-up the $1.33 million and another to implement the cost allocation,” Weissenborn said. Weissenborn said payments under a true-up will be a simple calculation, but the new cost allocation will be trickier: “The challenge that we have is that this is another new software change, but we will comply. We will get it done.”
Weissenborn said MISO will hold future stakeholder meetings on two remaining internal cost allocation issues under the settlement: how much entities with firm transmission that reduced the 1,000-MW capacity limit will have to pay and what cost allocation is needed for entities with capacity benefits that raised the Planning Resource Auction limit above 1,000 MW.
IMM Seasonal Review: Pricing Changes Still Needed
Independent Market Monitor David Patton used a review of last summer to continue his push for pricing changes.
Patton said summer’s 44% rise in energy prices over spring’s was due to increased natural gas prices and 1% larger year-over-year demand from summer 2015.
“Because of hot temperatures, we did rely more heavily on peaking resources,” Patton told the Market Subcommittee. The uptick led to more revenue sufficiency guarantee payments, culminating in a peak of almost $1.7 million in payments on July 21, when nearly all of MISO’s generating turbines were committed during a maximum generation event. The day also resulted in 1.6 GW of voluntary load curtailment, which lowered real-time energy prices to $36/MWh, even though the day-ahead price was $78/MWh. (See “IMM Makes Pricing Suggestions Following First Max Gen Event Since Polar Vortex,” MISO Markets Committee of the Board of Directors Briefs.)
“The problem with this is these are megawatts outside of MISO’s control,” Patton said. “You’re incurring an awful lot of costs just to turn these generators on. You’re certainly forcing the system to accept a lot of high-price energy. It makes it difficult to price the energy. …There are some things MISO could take a look at, and MISO is taking the process very, very slow.”
Patton repeated his suggestion that increasing the number of generators allowed to set prices under extended locational marginal pricing would temper erratic pricing.
“Procedures that say ‘turn everything on’ are not efficient, especially when there’s a more surgical” method, Patton said.
Jeff Bladen, executive director of MISO market services and liaison to the MSC, said the RTO will need to work with individual states and load-serving entities to improve the visibility of demand response. But he stood by the July 21 decision to issue the alert.
“What drove the over-commitment was not self-deployment. It was very much about the weather. Had the [stormy] weather in the forecast materialized, we would have absolutely needed the commitments,” Bladen said. Patton said he didn’t completely agree with that assessment.
Patton also said summertime outages that impacted constraints had a hand in increasing real-time congestion to $463.4 million in summer 2016 from $342.2 million in summer 2015.
MISO to Expand ELMP Price Setting, but not to IMM’s Specs
MISO Market Design Engineer Congcong Wang said the RTO is willing to expand ELMP to online resources with a one-hour start-up time without software changes.
The RTO says the possible expansion “captures a majority of peaking resources.”
Wang said the Monitor’s original recommendation that online price setting be spread to all resources with a two-hour minimum run time is neither cost effective nor beneficial with MISO’s current software. “The full expansion to two-hour minimum runtime will require software changes,” Wang said. (See MISO Study Undercuts IMM Proposal on Expanding ELMP Pricing.)
MISO’s path forward would increase eligible peaking resources from 8% to 58% on a capacity basis. Wang said the expansion without software changes captures about 60% of the Monitor’s recommendation “in terms of real-time commitment.”
With the addition of one-hour start-up units, ELMP price setting, which currently includes about 45 10-minute start-up units with a combined capacity of 1.2 GW, would increase to 179 units at 8.4 GW. The Monitor’s advice to include two-hour minimum runtime units would bring the number to 256 units at 14.4 GW.
However, MISO is not willing to budge on removing offline units from price setting in ELMP, another Monitor suggestion. Wang said MISO’s research shows that offline fast-start resource participation can address shortages. MISO said it “will work with its IMM to continue monitoring offline participation and will exclude a resource from pricing if it is found infeasible.”
Wang said MISO would likely make a final decision on resource pricing under ELMP at the December Market Subcommittee meeting.
If the RTO decides to go with the option that does not require a software change, Wang said implementation could begin in the first quarter of 2017.
The introduction of coordinated transaction scheduling with PJM will be delayed from March to next October, Bladen said during a Market Subcommittee liaison report.
Bladen said the date change is needed while MISO waits on PJM to complete market improvements and staff training. He added that joint filings will be made soon to update FERC on the later implementation date.
David Sapper of Customized Energy Solutions asked how stable CTS will be given that MISO is also trying to implement interface pricing rules with PJM. (See “No Consensus on Interface Pricing,” MISO/PJM Joint and Common Market Meeting Briefs.)
Bladen said while there is a relationship between the two market improvements, they aren’t related to a degree that would prevent them from being introduced independently.
“There’s no premise that you have to have one before the other,” he said. “They’re not intrinsically tied. They’re relative improvements of the same process.”
CTS is intended to reduce uneconomic flows between the two RTOs. The new product would allow traders to submit “price differential” bids that would clear when the price difference between MISO and PJM exceeds a threshold set by the bidder.
MISO Considering Moving Reserve Buy-Back into RSG
MISO is investigating a way to make up lost revenue for resources committed in real time that have previously cleared day-ahead offline supplemental reserves, said Jason Howard, MISO manager of market quality.
Currently, generators that commit in the real-time markets have to buy back their supplemental reserves.
MISO is considering providing make-whole payments to such generators through revenue sufficiency guarantee payments, Howard said. He said the proposal, which would require a Tariff change, would ensure that those units aren’t operating at a loss.
MISO looked at four years of historical data and found the average cost for buying back supplemental reserves amounts to $1 million per year across the RTO, Howard said.
CARMEL, Ind. — MISO’s Market Roadmap projects have been rearranged following stakeholder complaints over the lack of transparency behind the RTO’s reasoning for how it ranked them.
Stakeholders first raised their concerns over the rankings, and how MISO’s ordering was merged with stakeholders’ classification preferences, during the August Market Subcommittee meeting. The projects in the Market Roadmap, a work plan for market issues, were originally supposed to be ranked by early August.
“There were obviously some differences between what MISO and its stakeholders thought were priorities,” said Mia Adams, a senior market strategy analyst. Now, the four high-priority Market Roadmap projects are:
Aggregating load to meet minimum participation limits, which was previously ranked as a low priority by MISO;
Automatic generation control enhancement for fast-ramping resources, which was ranked high priority by stakeholders; MISO revised the priority from “low” in June to “high” in a second draft of the work plan in August;
Behind-the-meter storage aggregation under Type II demand response resources, which MISO previously gave a low priority; and
Introduction of multiday financial commitments, voted high priority by both MISO staff and stakeholders.
| MISO
With the reorder, MISO’s goals of developing additional short-term capacity reserve requirements and incorporating DR, emergency DR and boiler-turbine-generator deployment during capacity emergencies moved from high to medium priority. In addition, a pricing structure for voltage and local reliability commitments moved to low priority despite solid accord for a medium-priority ranking from the RTO and stakeholders.
The reorder provoked little discussion, as MISO almost completely aligned its prioritization with the stakeholders’ opinions.
MISO’s power marketers sector advocated that a virtual spread product be given high priority, but Adams said the RTO would need technological upgrades before it could complete the project. The issue was ranked low priority.
Of the 17 issues identified in the Market Roadmap process at the beginning of the year, five — including coordinated transaction scheduling with SPP — were placed in “parking lot” status, meaning they aren’t going to be given attention anytime soon.
MISO will unveil the final project prioritization in December.
Energy Future Holdings reached a major milestone in its Chapter 11 reorganization Monday, completing its tax-free spinoff of Luminant and TXU Energy into a new standalone company, TCEH Corp.
TCEH issued 427.5 million shares of common stock and other assets to the “pre-emergence” first-lien creditors of Texas Competitive Electric Holdings Co. It will trade on the OTCQX market under the ticker symbol THHH.
Luminant is Texas’ largest electric power generator with almost 17,000 MW of generation, including 2,300 MW of nuclear power, 8,000 MW of coal and 6,000 MW of natural gas. TXU Energy, a competitive retail electricity provider, has 1.7 million business and residential customers in Texas.
TCEH appointed as its CEO Curt Morgan, a consultant for the first-lien creditors and a former operating partner at private equity firm Energy Capital Partners. Also appointed to the board of directors were Gavin Baiera, Jennifer Box, Jeff Hunter, Michael Liebelson, Cyrus Madon and Geoffrey Strong.
In a statement Tuesday, Morgan said the company emerged from bankruptcy “with a strong balance sheet and the potential for stable earnings and significant cash generation,” having eliminated more than $33 billion of debt and other obligations and reduced its leverage to a low 2.3 times of gross secured debt to cash flow.
EFH said it was continuing its efforts to complete its reorganization with its sale of its 80% interest in Oncor, Texas’ largest transmission and distribution utility.
NextEra, EFH Seek to Reassure Texas PUC on Merger
Last week, EFH and NextEra Energy sought to assure Texas regulators they won’t be constrained in their review of NextEra’s agreement to purchase Oncor, which includes a $275 million termination fee.
During an update hearing Sept. 26 on EFH’s emergence from Chapter 11 bankruptcy (14-10979-CSS), Judge Christopher S. Sontchi said he had filed a joint letter from EFH and NextEra addressing the Public Utility Commission of Texas’ concerns.
PUC Commissioner Ken Anderson said during a Sept. 22 open meeting that the termination fee “appears to be an effort to really tie the commission’s hands in the proceeding,” as it would allow NextEra to cancel the deal if the commission imposed “overly burdensome” conditions. Anderson also called the fee an “improper attempt to constrain the commission.” (See Texas PUC Expresses Doubts over NextEra-Oncor Deal.)
NextEra has proposed buying Oncor for $18.7 billion.
According to the letter, “NextEra is not entitled to a termination fee under the merger agreement if NextEra Energy terminates the merger agreement because the commission either approves the merger agreement transaction with ‘burdensome conditions’ … or does not approve the merger agreement transaction.”
NextEra and EFH said the termination fee would be triggered only if EFH or Energy Future Intermediate Holding Co., Oncor’s direct parent, terminate the merger agreement. The companies wrote they “would like to make clear that, in any event, NextEra will not seek to collect any portion of the termination fee contemplated by the merger agreement in the event it terminates the agreement.”
Sontchi opened Monday’s hearing by quoting from the transcript of the PUC meeting.
“I believe [the] letter addresses the concerns raised by Commissioner Anderson,” Sontchi said. He said any possible triggering of the termination fee is “an issue for the bankruptcy court, and not for the PUCT and ratepayers.”
The PUC’s approval is just one of several favorable regulatory rulings NextEra and EFH must secure before closing the deal.
Arizona Public Service and Puget Sound Energy began transacting in the Western Energy Imbalance Market on Oct. 1, bringing the region’s only real-time market up to five members — including market operator CAISO.
Arizona Public Service and Puget Sound Energy are the newest members to join the Energy Imbalance Market.
The two utilities follow in the footsteps of NV Energy, which entered the market last December, and PacifiCorp, which helped launch the effort in November 2014.
“Participation by Arizona Public Service and Puget Sound Energy in the EIM will strengthen the market and yield substantial benefits in the form of access to low-cost energy for them and for all EIM participants,” CAISO CEO Steve Berberich said in a statement.
The EIM has produced $80 million in economic benefits for its members during the past two years, according to CAISO. Those benefits stem from more efficient inter- and intraregional dispatch in the 15-minute and real-time markets, lower curtailment of renewable energy and reduced need for market participants in all balancing areas to carry flexibility reserves.
Studies commissioned by the utilities indicate that APS could save $7 million to $18 million a year through EIM participation, while PSE could save between $18 million and $30 million.
“Participating in a market that enables APS to buy and sell power closer to when electricity is consumed will result in meaningful economic savings to customers through lower production costs and better integration of renewable resources like solar,” said Tammy McLeod, vice president of resource management at APS, which has transmission connections into both the CAISO and PacifiCorp-East balancing authority areas (BAAs).
PSE’s sole point of connection with the market is via a 300-MW long-term firm transmission reservation on the Bonneville Power Administration system that connects the utility with the PacifiCorp-West balancing authority area.
FERC last week authorized PSE to transact in the EIM at market-based rates, ruling that the company provided sufficient evidence that its limited link would not become constrained frequently enough to create an EIM submarket requiring measures to mitigate market power (ER10-2374).
The commission also directed APS to revise its proposed rules related to how resources external to the EIM can use dynamic scheduling to participate in the market through the utility’s transmission network. (See APS Ordered Again to Revise EIM Dynamic Scheduling Rules.)
Portland General Electric is scheduled to enter the EIM in October 2017, with Idaho Power slated to follow in April 2018.
RENSSELAER, N.Y. — The NYISOReliability Needs Assessment for 2017-2026 identified two transmission security needs beginning next year.
The assessment, which was approved by the Management Committee on Wednesday, identified the risk of thermal overloads on New York State Electric and Gas’ Oakdale 345/115-kV transformer in the Binghamton area and the Long Island Power Authority’s East Garden City-Valley Stream 138-kV line. Generation resources were deemed adequate in the period.
The Oakdale transformer overload was also mentioned in the 2014 assessment. NYSEG responded with plans for a third Oakdale transformer and reconfiguration of the Oakdale 345-kV substation. However, NYSEG has since updated the in-service date of the improvements from 2018 to the winter of 2021, the report said.
The LIPA 138-kV line has a risk of thermal overloads under N-1-1 conditions. “The power flow on this facility is driven by the combination of LIPA load in western Long Island and the scheduled 300-MW wheel between ConEdison and LIPA,” the report said.
Following the NYISO Board of Directors’ approval of the assessment, NYSEG and LIPA will be asked to develop solutions for the two transmission needs. If they are not addressed in their updated Local Transmission Owner Plans, the ISO will solicit solutions from developers.
The proposed solutions will be evaluated in the 2016 Comprehensive Reliability Plan. The RNA is the foundation for the reliability plan, which will be adopted next year.
Until upgrades can be completed, “the use of demand response and operating procedures, including load shedding under emergency conditions, may be necessary to maintain reliability during peak load periods,” the ISO said.
The biennial RNA process assumed the deactivation of the R.E. Ginna and James A. FitzPatrick nuclear plants. Those potential retirements were announced since the last Comprehensive Reliability Plan in 2014.
The plants, with a combined 1,463 MW, may be saved by the Clean Energy Standard adopted by the state’s Public Service Commission in August, which would pay upstate nuclear plants nearly $1 billion for their carbon-free attributes in the first two years of the program.
Systemwide Demand Response Activated
A summer heat wave prompted the first mandatory systemwide DR event in NYISO in three years.
The Aug. 12 event came on the second day of a two-day heat wave, when the peak load was 31,477 MW. NYISO estimated a peak of 32,415 MW if DR had not been activated.
Actual loads were 1,000 MW more than earlier projections for the day and came as neighboring control areas in Ontario and New England were also experiencing high demand. Operating reserves for some time intervals fell below the required 2,620 MW.
The summer’s peak was 32,076 MW on Aug. 11.
“The peak represented the third consecutive year that the NYISO peak fell below the 50/50 forecast,” said Wes Yeomans, NYISO’s operations vice president, who presented the summer 2016 report. The forecasted 50/50 peak was 33,360 MW.
Noteworthy over the two days was the performance of the state’s 1,700 MW of wind resources.
On Aug. 11, wind generation was essentially a flat line of about 50 MW from 8 a.m. to 8 p.m. On Aug. 12, as thunderstorm alerts began to move through the state, wind generation topped out at about 600 MW during the afternoon, closely following the rise in demand, which peaked in the 4 p.m. hour.
On July 24, NYISO activated its 21-hour notice for DR for the Lower Hudson Valley, New York City and Long Island, but the ISO did not implement its operation. Rochester Gas & Electric, Con Ed and the New York Power Authority instituted their voluntary DR programs, however.
The last systemwide DR event was during the polar vortex in January 2014 when the voluntary program was activated. The last mandatory DR systemwide event was in July 2013.
SAN DIEGO — Transmission industry owners, operators, generators, regulators, financiers and other key players from the Western U.S. attended Infocast’s 8th annual Transmission Summit West last week. They discussed the strategic, regulatory, investment and technology issues facing the industry.
Western Regionalization
CAISO’sStacy Crowley, vice president of regional and federal affairs, pushed the benefits of ISO participation in her solo presentation, saying, “Utilities and stakeholders have found these ISOs to be valuable, as far as providing cost-effective power.
“We know in the Midwest, states like Iowa could not have reached their renewable standards without an ISO. We’ve seen entities around the Northwest asking if there are efficiencies with a larger market. Clearly, a board appointed by the California governor and approved by the State Senate would not fly in a regional ISO. California clearly has the largest load of any state in the West, but a regional ISO must speak for everyone and their policies.”
ColumbiaGrid CEO Patrick Damiano agreed, but he made the case that coordinating planning doesn’t require a centralized market.
ColumbiaGrid conducts transmission planning and other coordination for its eight members: Avista, Bonneville Power Administration, Chelan County Public Utility District, Grant County PUD, Seattle City Light, Snohomish County PUD, Tacoma Power and Puget Sound Energy, which joined the Western Energy Imbalance Market on Oct. 1.
“The Northwest has always been an active bilateral market,” Damiano said.
“We’ve been very excited about the creation of the EIM,” said Gerald Deaver, manager of regional transmission policy for Xcel Energy. “Our first baby step was FERC’s approval of a joint dispatch area in Colorado [with Platte River Power Authority]. We’ll be the market operator, but we look at it as a way to more efficiently use generation resources in the balancing area. Our ultimate goal is to develop a larger geographic footprint to better integrate renewables. Our hope is that entities will become more comfortable operating in that environment.”
“I can’t imagine all of the West as we know it today would be one RTO. It’s too big. I see two or three RTOs with seams agreements,” SouthWestern Power Group’s Tom Wray said. “For resource management and market efficiency, [RTOs] are clearly a good policy move for the country. One of the motivating factors for expansion of the regional market we know as Cal-ISO is largely coming from regulatory pressure.”
Tanya Bodell, executive director of Energyzt, called for “market-based solutions” to cope with too much generation on the Western system. “West Texas retailers are selling energy for free on nights and weekends. FERC Order 745 has opened up an opportunity for demand to come into the market. I can see 745 creating a mechanism through which system operations encourage people and pay people to use more energy. Generators have a different bid price to operate, versus a bid price to curtail. You may end up getting a curtailment market, where the ISO asks for bids from generators.”
Renewable Integration Remains Sticky Issue
“We’ve done pretty well so far in integrating renewables. We didn’t think 20% would be that easy, but it turned out to be not so much of a challenge,” said Carl Zichella, director of Western transmission for the Natural Resources Defense Council. “We have 38 different balancing authorities in the West. It’s one big grid operating in discrete chunks, rather than an integrated system. While that’s worked so far, we’re going to need to do much better to integrate deeper penetration of wind.
“The worst-case scenario for renewables is what we have now … [balancing authorities] complicating the use of transmission with bilateral contracts and artificial congestion. The biggest hurdle to regionalization is the governmental structure.”
Jay Caspary, SPP’s director of research, development and Tariff studies, said America’s best renewable resources straddle the seam between the Western and Eastern interconnections. While SPP, MISO and ERCOT have built and continue to build transmission to access those resources, the abundance does create a dilemma.
“ERCOT is harvesting thousands of megawatts in SPP’s backyard and pulling them into ERCOT,” he said. “We have two separate independent networks in the Texas Panhandle. At some point, we’ll probably have to integrate those two, but there are a lot of jurisdictional issues.”
In California, rooftop solar is the oncoming train. Jack Moore, director of market analysis for Energy + Environmental Economics, said his company is projecting the state will enjoy 17 to 23 GW of the sunshine resource by 2025. “The big driver we see is in certain hours, California has more solar than it can use. That does set up a reason for [increased] transmission to be able to bring more flexibility to the system.”
“Our experience in Texas is that you build these [interconnection] ties and they get oversubscribed,” said Bill Bojorquez, vice president for Hunt Power. “There are great stranded resources in New Mexico. Sharyland Utilities has over 11 [GW] of generator-interconnection requests. We are literally over-subscribed. It’s one of those stories where if you build it, they’ll be oversubscribed.”
Getting Utilities to Embrace Alternative Technologies
Several speakers complained about the industry’s conservatism.
William White, director of public affairs for CTC Global, said his company has found it difficult winning acceptance of its high-temperature, low-sag, composite core conductors. “We’re in the odd position of having a proven product that works,” he said. “We know it works, our customers know it works, but old habits die hard. Most of [today’s] conductors are literally 100-year-old technology.”
“Some of the biggest resistance to regionalization is the cost,” said Gregg Rotenberg, president of Smart Wires, which provides “grid optimization solutions.”
“If we’re having a conversation about regionalization and we’re only using existing infrastructure, that means we’re using the grid inefficiently,” Rotenberg said. “The hardest group to get involved is the transmission groups at these utilities. When we get them on an equal playing field and we’re spending less on new technologies, we’ll have a new grid.”
Byron Woertz Jr., the Western Electricity Coordinating Council’s manager of system adequacy planning, preferred to see his glass half full. “This a country that put a man on the moon with 20th century technology, so I think we can improve the grid,” he said.
Battery Storage Ready for Prime Time
Asked whether battery storage needs tax credits similar to wind and solar resources, Kiran Kumaraswamy, market development director for AES Energy Storage, said storage is “absolutely ready for prime time.”
“What we really need is a framework to value this class of resources. Four to five years ago, we started talking about the value of solar in a way in which you could bring all those benefits to the table and compare them with all the other options. The gap right now is being able to evaluate [storage] resources on an apples-to-apples basis.”
“I think energy storage works best when paired with other grid assets, to increase the value of the electricity being generated,” said John Jung, CEO of Greensmith Energy Management Systems. “You can do a lot more with electricity when you have the ability to shape the nature of it and the quality of it.”
John Fernandes, RES Americas’ director of policy and market development, said he is not worried about customer migration from the grid. “I’ve been announcing the death spiral of the utility death spiral for years now.”
Non-utilities “are not dealing with NERC violations worth millions of dollars a day,” he said. “When you’re talking about megawatts, [reliability] matters. We’re so highly dependent on this super-reliable service.”
Making FERC Order 1000 Work
A panel sharing their experiences with FERC Order 1000’s directive on competitive transmission projects agreed that CAISO continues to put space between itself and other RTOs with its implementation of the order.
“The evaluation process is certainly evolving. Cal-ISO maybe puts more emphasis on costs and less emphasis on [operations and maintenance], but it’s gotten much better,” said Charlie Adamson, principal manager of major transmission and distribution projects for Southern California Edison. “Every evaluation, they’ve gotten better at it. Things like the EIM or the ultimate experience of an ISO … opens up market availabilities for that energy transfer to make sense. Over time, that could enable long-haul lines that bring in energy from where it’s cheap to where it’s necessary.”
Josh Burkholder, director of transmission asset strategy and grid development for AEP Transmission and Transource Energy, relayed his experiences in SPP’s first competitive process, which resulted in one project being awarded — and then canceled as unneeded. “There were some real head scratchers [in how an industry expert panel graded the projects]. A notch difference in your parent company’s credit rating was a five-point difference [in the scoring]. In a $10 million project, [the credit rating is] pretty irrelevant. Be careful what you wish for a little bit, when it comes to clarity and understanding with how the decision is made.”
“From my standpoint, a lot of things that may not be apparent may become a reliability issues when it’s too late to solve the issue with transmission,” said Bob Smith, vice president of transmission development for TransCanyon, a joint venture of Pinnacle West Capital and Berkshire Hathaway Energy. “This is the second year we’ve had laws in California that are going to require a 50% [renewable portfolio standard], maybe higher, to comply with greenhouse gas laws. Yet, Cal-ISO is relying on a 20% portfolio? It doesn’t make sense for Cal-ISO to be planning when you don’t know where the resources are. By the time Cal-ISO gets clarity on where resources are, we’re coming pretty close to 12 years from the 2030 policy deadline, and you don’t develop transmission in three or four years.”
Speaking of transmission projects in general, Chris Jones, a vice president with Duke-American Transmission Co., said delays in the permitting process “that can happen over the decades-long process” remains “the biggest risk in each of our projects.”
“One of the things that’s changed since I started doing this work is the sensationalism of these projects and the media coverage you get and the protests that come with that. It’s usually local groups, but we’re seeing more and more groups outside the [non-governmental organizations] get media coverage. You’re seeing that now with the North Dakota pipeline project.”
Ali Amirali, a senior vice president with the Starwood Energy Group, called transmission development “a giant game of economic chicken.” He said, “The generation developers are waiting for the transmission to be built. The transmission developers want the generation to be built before getting into the heavy capitalization of transmission.”
California and Massachusetts tied for first place in the 2016 State Energy Efficiency Scorecard published by the American Council for an Energy-Efficient Economy. This is the sixth consecutive year that Massachusetts led the nation.
Missouri, Maine and Michigan were the most-improved states, according to the study. The study identified Louisiana, Kansas, South Dakota, Wyoming and North Dakota as the states most in need of improvement.
“States are spurring efficiency investment through advancements in building energy codes, transportation planning and leading by example in their own facilities and fleets. These investments reap large benefits, giving businesses, governments and consumers more control over how and when they use energy,” said ACEEE Executive Director Steven Nadel.
Utilities: Customers Subsidizing Rooftop Solar Homes
Arizona Public Service and the Salt River Project say that customers who have installed rooftop solar panels on their homes are increasingly burdening those who haven’t.
SRP recently told a local newspaper that its “demand charge” of about $50 on rooftop solar customers was necessary because they weren’t paying their fair share for the energy they consumed from the grid. APS said 96% of its customers pay more than they should because of state subsidies for rooftop solar installations. The utility is seeking a new rate plan from state regulators.
The solar industry in the state disputes these statements. SolarCity is suing SRP over the extra charge, while groups such as the Arizona Solar Energy Industries Association and Solar Strong America say the utilities are trying to undermine net metering in the state.
Water District Installing Largest Public Energy Storage System
The Irvine Ranch Water District is installing a 7-MW, 34-MWh energy storage system using Tesla batteries in what is billed as the largest network of energy storage systems at a public water agency in the U.S.
Irvine Ranch is working with Advanced Microgrid Solutions to install the battery storage system at three water treatment plants, a deep aquifer treatment system, a desalinization plant and six large pumping stations. The district decided on the system after regulators called on utilities and municipalities to install systems to provide power in the event of service interruptions.
“In a region challenged by the closure of the San Onofre Nuclear Generating Station,” Irvine Ranch said. The project will allow it to reduce demand from the grid when requested by the utility without curtailing water treatment operations.
Pacific Gas and Electric last week filed a response to public comments submitted to the Public Utilities Commission on its plan to retire its Diablo Canyon nuclear plant in 2025.
“We fully understand that elements of the joint proposal reflect important issues for the state and PG&E’s customers,” PG&E Electric President Geisha Williams said in a statement. “The near decade-long period ahead of us provides the time to plan and replace Diablo Canyon’s energy with new [greenhouse gas]-free replacement resources.”
The company, which reached a settlement over the plan with employees and environmental groups in August, said it did not expect rates to increase as a result of the closure.
Gov. Jerry Brown signed a bill last week that requires participants in energy efficiency programs for heating and air conditioning to provide proof that their equipment has been properly installed.
“Research shows that many of these projects are not being installed correctly, meaning customers aren’t receiving the energy efficiency savings they paid for and could even be dealing with a significant safety hazard,” said State Sen. Lois Wolk, the bill’s sponsor. Wolk said the bill would also help the state meet its goals to combat climate change.
Brown also signed a package of bills designed to increase transparency and public participation in Public Utilities Commission hearings and proceedings. The bills were written after the deadly explosion of a Pacific Gas and Electric natural gas pipeline revealed off-the-record, private communications between the commission and the companies it regulates.
Construction of a proposed NRG Energy power plant in Oxnard may be delayed after the company made some changes to its design, the state Energy Commission said at a public hearing last week.
NRG decided to change how the plant’s water discharge is routed. The commission said that means it will require more data from the company before it can give final approval to the plant, which has been sited at a local beach. A final staff report was expected by Oct. 14, but that may need to be pushed back, the commission said.
The plant, called the Puente Project, is intended to replace two aging generators in the area.
The Commerce Commission voted unanimously to accept Ameren Illinois’ plan to expand the installation of smart meters to its entire service territory.
Currently, just 330,000 of the company’s 1.2 million customers have smart meters installed. Ameren had originally planned to expand to just 62% of its customers, but the utility decided to expand the program once it found that the meters reduced outages and saved money for both it and its customers.
The Environmental Defense Fund and the Citizens Utility Board both supported the plan. Installations will be completed by 2019.
Former PUB Member: Hydro Customers Facing Giant Rate Hikes
An over-budget transmission project, coupled with increased charges from dam construction, could double rates for Manitoba Hydro customers, according to a former Public Utilities Board member.
Graham Lane, a former PUB chairman and chartered accountant, said mounting debts from the Bipole III transmission line project and the Wuskwatim dam could spur Manitoba Hydro to seek major rate hikes.
“The losses [associated with the projects] are going to be huge,” he said. “By my own calculations, by the time it all ends, Hydro will have lost somewhere in the area of $5 billion to $10 billion, and that money will basically have to be covered by the ratepayers.”
State officials released proposed fracking regulations last week that would ban drilling in three watersheds in Western Maryland and require four layers of steel casing and cement around wells to prevent water, gas and other fluids from migrating.
Environment Secretary Ben H. Grumbles called the proposed regulations “the most stringent” in the country. However, the rules would allow drill sites closer to homes and private wells than proposed by former Gov. Martin O’Malley (D).
The state legislature imposed a moratorium on fracking that is due to expire in October 2017. Environmentalists say they will try next year to make the moratorium permanent.
The Montana Environmental Information Center and Vote Solar filed a complaint with FERC claiming the Public Service Commission violated federal regulations when it suspended payments for energy projects while it reviews standard rates for small solar energy developers.
“That rate has now been taken off the table when projects were in their late stages,” said Brian Fadie, clean energy program director for MEIC. “It undercuts solar development in Montana at the moment.”
A hearing on new rates could come as early as January, PSC spokesman Eric Sell said.
A special legislative committee on climate change is seeking to create a statewide climate action plan — addressing issues such as solar energy and financing energy improvement.
“Some of the public power districts have created their own, what I would say, goals. Nebraska Public Power District, I think their goal is 10%,” state Sen. Ken Haar said. The districts’ goals “are fairly low compared to what other states are doing that actually have energy standards.”
Harr said the committee will issue a report to the Legislature by the end of the year.
Empire Center Critical of PSC’s Clean Energy Standard
The Empire Center for Public Policy has issued a report critical of the Public Service Commission’s Clean Energy Standard, passed in August, which calls for 50% of the state’s energy needs to come from renewable sources by 2030.
The think tank says that rather than subsidizing renewables, the PSC should set greenhouse emission standards and let utilities figure out how to meet them. The group, which promotes “free-market principles [and] personal responsibility,” also maintains that the cost of ramping up renewables will exceed the $2/month rate increase that the commission predicted and that it underestimated the difficulty of switching to solar and wind power.
PSC spokesman Jon Sorensen defended the plan. “Rather than support bold national leadership to combat the very real threat of climate change, this right-wing think tank denies reality and relies on bogus cost assumptions to argue for inaction,” Sorensen said in a prepared statement.
Long Island has seen a 320% growth in solar energy over the past four years and just completed its 35,000th solar energy project, Gov. Andrew Cuomo announced.
Long Island, which is part of NY-Sun, the $1 billion initiative launched by Cuomo to advance the solar industry and create jobs, now saves 200,000 tons of carbon emissions per year.
“Clean energy is our future, and Long Island is leading the state in growing our clean tech economy and achieving our climate change goals,” Cuomo said.
Two Sides Clash over Environmental Justice Reports
State regulators and environmentalists are clashing over reports that say new coal ash landfills at Duke Energy’s Sutton Plant in Wilmington and Dan River plant in Eden won’t unfairly affect anyone based on age, race, income or language.
The findings were the first two environmental justice reports issued by state regulators since announcing in April that they would start requiring environmental justice reviews before issuing permits.
Therese Vick, a community organizer with the Blue Ridge Environmental Defense League, said the reviews are not worth much because there is no mechanism to deny a permit on environmental justice grounds. “It’s an empty process,” she said.
Duke Energy Progress is seeking to build a new 230-kV transmission line in Bladen County that would connect Innovative Solar’s new 40-MW solar power facility in Bladen County to Duke’s existing Cumberland to Delco 230-kV transmission line in Bladen County.
In its September application filed with the Utilities Commission, Duke said it will build a 230-kV breaker station adjacent to a new substation that Innovative Solar plans to build adjacent to the Cumberland to Delco 230-kV line.
The Power Sitting Board has given approval to Boston-based Advanced Power Services for a $1.1 billion, 1,105-MW natural gas-fired power plant in eastern Ohio.
The plant is expected to begin operating in January 2020.
Kasich Threatens Veto of Any Bill Killing Clean Energy Standards
Kasich
Gov. John Kasich threatened to veto any legislation eliminating standards for renewable energy and energy efficiency, which could be a bad sign for proposals pending in the General Assembly.
Two years ago, Kasich placed a freeze on standards requiring electricity utilities to meet annual benchmarks for renewable energy and to help customers reduce energy use. The freeze will expire soon, and not all lawmakers would like to see it extended.
Pacific Power announced last week that four solar power projects in central and southern Oregon from which it acquired future renewable energy credits would not be completed until the first quarter of 2017.
The company previously expected the developer, Coronal Development, to complete the projects by year-end.
If Coronal misses its completion date, it is contractually obligated to pay Pacific the difference if it has to buy power at a higher cost on the energy market.
A dispute is raging in the state between drillers and landowners, who claim they are being cheated out of royalty payments for gas extracted from their land.
Although a 1979 law mandates a landowner royalty of at least 12.5% of the value of the gas, there are disputes over how the gas should be valued. Landowners contend they are entitled to 12.5% of what the gas sells for, while drillers say the proper calculation is market price, less post-production deductions for transportation and processing.
State lawmakers are scheduled to take up the issue Tuesday with a procedural vote on a bill that would prevent deductions from reducing landowner royalties to below the 12.5% state minimum.
Supreme Court Strikes Down Pro-Industry Drilling Law Provisions
The state Supreme Court last week struck down provisions of a 2012 law allowing state utility regulators to punish municipalities financially if they enact drilling rules stricter than state law.
The provisions generally had not been used, but the decision gives municipalities “breathing room” to enact tougher ordinances on the natural gas industry, said Jordan Yeager, an attorney for the Delaware Riverkeeper Network.
The high court also struck down two other provisions of the law. One pertained to a so-called “medical gag” rule; the other was characterized by one justice as illegal eminent domain for a private purpose.
State’s Pipeline Infrastructure not Keeping Pace with Gas Production
The state’s 60,000 miles of pipeline infrastructure is not keeping pace with natural gas production, industry leaders said in a conference call last week that addressed future gas pipeline expansion.
Some 25 to 30% of the state’s wells do not have full takeaway capacity, said Stephanie Catarino Wissman, executive director of Associated Petroleum Industries of Pennsylvania. The lack of pipeline infrastructure is hurting production from the Marcellus and Utica shales, Wissman said.
Pierre, state and company officials held a ribbon cutting ceremony last week for the state’s largest solar project, which has begun generating power under a testing period before it starts feeding the grid Oct. 7.
The $2 million, 1-MW facility is a joint venture between Pierre, Geronimo Energy and Missouri River Energy Services. It is located on about nine acres near the city’s airport. The companies chose Pierre because of easy access to a substation and available land that could not be used to grow crops.
With 4,280 panels, the facility only took two months to build, an MRES official said.
McAuliffe Rejects Calls To Kill Atlantic Coast Pipeline
Amid protests from residents and environmentalists, Gov. Terry McAuliffe said last week that he lacks the authority to cancel construction of Dominion Resources’ Atlantic Coast Pipeline — and wouldn’t do so even if he could.
“I as governor do not have the right to call down to the Department of Environmental Quality and say, ‘Well I don’t like this,’” McAuliffe said on a local radio station. “I cannot deny an air and water permit as governor. I don’t have the authority. It’s done by statute. If you don’t like the regs and they get approved, then you need to talk to the legislature to change the law.” But the governor also said he supports the project, arguing that it will create jobs and is a safer alternative to transporting gas by train.
McAuliffe’s remarks come as about 150 people attended a public hearing of the Buckingham County Planning Commission to voice to their opposition to the pipeline. Because of the large turnout, the commission extended the public comment period to Oct. 17. The Chesapeake Climate Action Network is also planning a three-day protest outside the Executive Mansion in Richmond.
The state’s big gas utilities are filing legal challenges to a recent Department of Ecology rule that requires about two dozen large industrial emitters of greenhouse gases to reduce their carbon emissions by an average of 1.7% annually.
The rule applies to the state’s five oil refineries, Puget Sound Energy gas facilities in Sumas, Longview and Goldendale, and other large emitters, including the Grays Harbor Energy Center in Elma.
“Washington’s natural gas utilities believe that reducing greenhouse gas emissions is a matter that needs addressing, but the [Clean Air Rule] is not the solution,” Avista said in a statement.
Mayors, Consumer Groups Protest FirstEnergy Plant Sale
More than a dozen groups, including city officials, energy efficiency organizations, natural gas companies and consumer advocates, have sent a letter to the Public Service Commission to protest FirstEnergy’s sale of the Pleasants power plant to one of its subsidiaries.
The groups say FirstEnergy is trying to save the money-losing coal plant by selling it to either Mon Power or Potomac Edison, which can get a guaranteed rate of return for the plant’s power. They told the PSC the utilities should bid for the lowest cost power, and that FE should have to prove selling the plant to one of the utilities is the most affordable option for consumers.
Fitch downgraded the state’s credit rating from AA+ to AA, citing the failing coal industry and a slump in profitability from natural gas.
The agency did note the growth in the service, transportation and warehousing industries, but they were not enough to buoy the state’s economy, which still relies heavily on coal. The state is also steadily losing its population to other states, Fitch said.
“We must work continually to diversify our economy through projects like the Hobet mine site redevelopment, while also maintaining a balanced, smart budget without irresponsible cuts to critical programs,” Gov. Earl Ray Tomblin said.
Legislative Committee Kills Wind Production Tax Increase
A state legislative committee voted down a proposed increase on the state’s wind energy production tax, the only such tax in the country.
The legislature has been seeking a way to close a multimillion-dollar budget shortfall, caused in part by a decline in revenue from the fossil fuel industries. But after hearing five hours of testimony from wind companies and local communities, the committee voted against moving forward a bill that would have raised the wind tax from $1/MWh to $3. Everyone who spoke at the hearing on the bill was against it.
Rep. Michael Madden, a committee co-chair, supported the bill, pointing to a new wind project that would have raised $40 million alone. The state is facing a gap of $200 million. “I don’t know what we’re going to do now,” Madden said.
Missouri, Maine and Michigan were the most-improved states, according to the study. The study identified Louisiana, Kansas, South Dakota, Wyoming and North Dakota as the states most in need of improvement.
Arizona Public Service and the Salt River Project say that customers who have installed rooftop solar panels on their homes are increasingly burdening those who haven’t.
The Irvine Ranch Water District is installing a 7-MW, 34-MWh energy storage system using Tesla batteries in what is billed as the largest network of energy storage systems at a public water agency in the U.S.
Pacific Gas and Electric last week filed a response to public comments submitted to the Public Utilities Commission on its plan to retire its Diablo Canyon nuclear plant in 2025.
Construction of a proposed NRG Energy power plant in Oxnard may be delayed after the company made some changes to its design, the state Energy Commission said at a public hearing last week.
The Commerce Commission voted unanimously to accept Ameren Illinois’ plan to expand the installation of smart meters to its entire service territory.
An over-budget transmission project, coupled with increased charges from dam construction, could double rates for Manitoba Hydro customers, according to a former Public Utilities Board member.
The Montana Environmental Information Center and Vote Solar filed a complaint with FERC claiming the Public Service Commission violated federal regulations when it suspended payments for energy projects while it reviews standard rates for small solar energy developers.
State regulators and environmentalists are clashing over reports that say new coal ash landfills at Duke Energy’s Sutton Plant in Wilmington and Dan River plant in Eden won’t unfairly affect anyone based on age, race, income or language.
Pacific Power announced last week that four solar power projects in central and southern Oregon from which it acquired future renewable energy credits would not be completed until the first quarter of 2017.
The state’s 60,000 miles of pipeline infrastructure is not keeping pace with natural gas production, industry leaders said in a conference call last week that addressed future gas pipeline expansion.
Pierre, state and company officials held a ribbon cutting ceremony last week for the state’s largest solar project, which has begun generating power under a testing period before it starts feeding the grid Oct. 7.
Amid protests from residents and environmentalists, Gov. Terry McAuliffe said last week that he lacks the authority to cancel construction of Dominion Resources’ Atlantic Coast Pipeline — and wouldn’t do so even if he could.
More than a dozen groups, including city officials, energy efficiency organizations, natural gas companies and consumer advocates, have sent a letter to the Public Service Commission to protest FirstEnergy’s sale of the Pleasants power plant to one of its subsidiaries.
itch downgraded the state’s credit rating from AA+ to AA, citing the failing coal industry and a slump in profitability from natural gas.